~~Tengasco, Inc. and Subsidiaries~~

~~Condensed Consolidated Balance Sheets~~

~~(unaudited)~~

~~(in thousands, except share data)~~

September 30,
2020

December 31,
2019

Assets

Current
Cash and cash equivalents
$
2,545

$
3,055

Accounts receivable
262

557

Inventory
302

415

Prepaid expenses
156

247

Other current assets
4

4

Total current assets
3,269

4,278

Loan fees, net
2

4

Right of use asset - operating leases
58

41

Oil and gas properties, net (full cost accounting method)

3,914

4,385

Other property and equipment, net
134

149

Accounts receivable - noncurrent
—

65

Total assets
$
7,377

$
8,922

~~See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.~~

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

~~Condensed Consolidated Balance Sheets~~

~~(unaudited)~~

~~(in thousands, except share data)~~

September 30,
2020

December 31,
2019

Liabilities and Stockholders’ Equity

Current liabilities
Accounts payable – trade
$
304

$
269

Accrued liabilities
255

164

Lease liabilities - operating leases - current
58

41

Lease liabilities - finance leases - current
58

61

Current maturities long-term debt
101

—

Asset retirement obligation - current
75

75

Total current liabilities
851

610

Lease liabilities - finance leases - noncurrent
42

41

Long-term debt, less current maturities
65

—

Asset retirement obligation - noncurrent
1,954

1,923

Total liabilities
2,912

2,574

Commitments and contingencies (Note 10)
Stockholders’ equity
Preferred stock, 25,000,000 shares authorized:
Series A Preferred stock, $0.0001 par value, 10,000 shares designated; 0 shares issued and outstanding
—

—

Common stock, $0.001 par value, authorized 100,000,000 shares, 10,680,050 and 10,658,775 shares issued and outstanding
11

11

Additional paid–in capital
58,304

58,293

Accumulated deficit
(53,850
)

(51,956
)
Total stockholders’ equity
4,465

6,348

Total liabilities and stockholders’ equity
$
7,377

$
8,922

~~See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.~~

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Condensed Consolidated Statements of Operations~~

~~(unaudited)~~

~~(in thousands, except share and per share data)~~

For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,

2020 2019 2020 2019
Revenues
Oil and gas properties
$
765

$
1,215

$
2,292

$
3,777

Total revenues
765

1,215

2,292

3,777

Cost and expenses
Production costs and taxes
746

913

2,399

2,604

Depreciation, depletion, and amortization
146

186

461

566

General and administrative
685

297

1,324

913

Total cost and expenses
1,577

1,396

4,184

4,083

Net loss from operations
(812
)

(181
)

(1,892
)

(306
)
Other income (expense)
Interest expense
(2
)

(2
)

(6
)

(8
)
Gain on sale of assets
1

1

4

45

Total other income (expense)
(1
)

(1
)

(2
)

37

Net loss from operations before income tax
(813
)

(182
)

(1,894
)

(269
)
Deferred income tax benefit (expense)
—

—

—

—

Net loss
$
(813
)

$
(182
)

$
(1,894
)

$
(269
)
Net loss per share
Basic and fully diluted
$
(0.08
)

$
(0.02
)

$
(0.18
)

$
(0.03
)
Shares used in computing earnings per share
Basic and fully diluted
10,680,050

10,653,550

10,673,238

10,648,838

~~See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.~~

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Condensed Consolidated Statements of Cash Flows~~

~~(unaudited)~~

~~(in thousands)~~

For the Nine Months Ended
September 30,

2020 2019
Operating activities
Net loss
$
(1,894
)

$
(269
)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization
461

566

Amortization of loan fees-interest expense
2

4

Accretion on asset retirement obligation
94

100

Gain on asset sales
(4
)

(45
)
Stock based compensation
11

14

Changes in assets and liabilities:
Accounts receivable, current and noncurrent
360

22

Inventory, prepaid expenses and other assets
204

78

Accounts payable
118

4

Accrued and other current liabilities
96

(51
)
Settlement on asset retirement obligation
(13
)

(52
)
Net cash (used in) provided by operating activities

(565
)

371

Investing activities
Additions to oil and gas properties
(103
)

(153
)
Proceeds from sale of oil and gas properties
36

41

Additions to other property and equipment
(10
)

(2
)
Proceeds from sale of materials inventory
—

150

Net cash (used in) provided by investing activities
(77
)

36

Financing activities
Repayments of financing leases
(34
)

(40
)
Proceeds from borrowings
166

—

Net cash provided by (used in) financing activities
132

(40
)
Net change in cash and cash equivalents
(510
)

367

Cash and cash equivalents, beginning of period
3,055

3,115

Cash and cash equivalents, end of period
$
2,545

$
3,482

Supplemental cash flow information:
Cash interest payments
$
4

$
4

Supplemental non-cash investing and financing activities:
Financed company vehicles
$
54

$
30

~~See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.~~

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Changes in Stockholders’ Equity~~

~~(unaudited)~~

~~(In thousands, except per share and share data)~~

Nine Months Ended September 30, 2020:
Common Stock
Paid-in
Capital

Accumulated
Deficit
Total
Shares Amount
Balance, December 31, 2019
10,658,775

$
11

$
58,293

$
(51,956
)

$
6,348

Net loss
—

—

—

(527
)

(527
)
Compensation expense related to stock issued
7,436

—

4

—

4

Balance, March 31, 2020
10,666,211

$
11

$
58,297

$
(52,483
)

$
5,825

Net loss
—

—

—

(554
)

(554
)
Compensation expense related to stock issued
7,328

—

3

—

3

Balance, June 30, 2020
10,673,539

$
11

$
58,300

$
(53,037
)

$
5,274

Net loss
—

—

—

(813
)

(813
)
Compensation expense related to stock issued
6,511

—

4

—

4

Balance, September 30, 2020
10,680,050

$
11

$
58,304

$
(53,850
)

$
4,465

Nine Months Ended September 30, 2019:
Common Stock Paid-in Accumulated
Shares Amount Capital Deficit Total
Balance, December 31, 2018
10,639,290

$
11

$
58,276

$
(51,520
)

$
6,767

Net loss
—

—

—

(96
)

(96
)
Compensation expense related to stock issued
4,962

—

4

—

4

Balance, March 31, 2019
10,644,252

$
11

$
58,280

$
(51,616
)

$
6,675

Net income
—

—

—

9

9

Compensation expense related to stock issued
4,411

—

6

—

6

Balance, June 30, 2019
10,648,663

$
11

$
58,286

$
(51,607
)

$
6,690

Net loss
—

—

—

(182
)

(182
)
Compensation expense related to stock issued
4,887

—

4

—

4

Balance, September 30, 2019
10,653,550

$
11

$
58,290

$
(51,789
)

$
6,512

~~See accompanying Notes to Unaudited Condensed Consolidated Financial Statements.~~

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~(1) Description of Business and Significant Accounting Policies~~

Tengasco, Inc. (the “Company”) is a Delaware corporation. The Company is in the business of exploration for and production of oil and natural gas. The Company’s primary area of exploration and production is in Kansas.

~~Basis of Presentation~~

The accompanying unaudited condensed consolidated financial statements as of September 30, 2020 and September 30, 2019 have been prepared in accordance with generally accepted accounting principles in the United States of America (“U.S. GAAP”) for interim financial information and with the instructions toThis Quarterly Report on Form 10-Q contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and ~~Item 210~~Section 21E of ~~Regulation S-X. Accordingly, they~~the Securities Exchange Act of 1934, as amended. The statements contained in this report that are not historical facts are forward-looking statements that represent management’s beliefs and assumptions based on currently available information. Forward-looking statements include information concerning our possible or assumed future results of operations, business strategies, need for financing, competitive position and potential growth opportunities. Our forward-looking statements do not consider the effects of future legislation or regulations. Forward-looking statements include all statements that are not historical facts and can be identified by the use of forward-looking terminology such as the ~~information and footnotes required~~words “believes,” “intends,” “may,” “should,” “anticipates,” “expects,” “could,” “plans,” “estimates,” “projects,” “targets” or comparable terminology or by ~~U.S. GAAP for complete financial statements. The condensed consolidated balance sheet as~~discussions of ~~December 31, 2019 is derived from the audited financial statements but does not include all disclosures required by U.S. GAAP. The Company believes~~strategy or trends. Although we believe that the ~~disclosures made~~expectations reflected in such forward-looking statements are adequate to make the information not misleading. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation for the periods presented have been included as required by Regulation S-X, Rule 10-01. Operating results for the three months and nine months ended September 30, 2020 are not necessarily indicative of the results that may be expected for the year ended December 31, 2020. It is suggestedreasonable, we cannot give any assurances that these ~~condensed consolidated financial~~expectations will prove to be correct. Such statements ~~be read~~by their nature involve risks and uncertainties that could significantly affect expected results, and actual future results could differ materially from those described in ~~conjunction with~~such forward-looking statements.

Among the ~~Company’s consolidated financial statements~~factors that could cause actual future results to differ materially are the risks and ~~footnotes thereto included~~uncertainties discussed in ~~the Company’s Annual Report~~this report and in our annual report on Form 10-K for the year ended December 31, ~~2019.~~2020. While it is not possible to identify all factors, we continue to face many risks and uncertainties including, but not limited to:

•fluctuations in the price we receive for our oil, gas, and NGL production, including local market price differentials;

~~Principles~~•the impact of ~~Consolidation~~the COVID-19 pandemic, including reduced demand for oil and natural gas, economic slowdown, governmental and societal actions taken in response to the COVID-19 pandemic, and stay-at-home orders or illness that may cause interruptions to our operations;

•cost and availability of gathering, pipeline, refining, transportation and other midstream and downstream activities and our ability to sell oil, gas, and NGLs, which may be negatively impacted by the COVID-19 pandemic;

•severe weather and other risks and lead to a lack of any available markets;

•risks related to our recently completed Merger, including challenges associated with integrating operations and diversion of management’s attention to Merger-related issues;

•our ability to successfully complete mergers, acquisitions and divestitures;

•risks relating to our operations, including development drilling and testing results and performance of acquired properties and newly drilled wells;

•any reduction in our borrowing base from time to time and our ability to repay any excess borrowings as a result of such reduction;

•the impact of our derivative instruments and hedging activities;

•continuing compliance with the financial covenants contained in our credit agreement;

•the loss of certain federal income tax deductions;

•risks associated with executing our business strategy, including any changes in our strategy;

•inability to prove up undeveloped acreage and maintaining production on leases;

•risks associated with concentration of operations in one major geographic area;

•deviations from our forecasts and budgets, including our 2021 capital expenditure budget;

•the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil exporting nations to agree to, adhere to and maintain oil price and production controls;

•legislative or regulatory changes, including initiatives related to hydraulic fracturing, emissions, and disposal of produced water, which may be negatively impacted by the recent change in Presidential administration or legislatures;

•the ability to receive drilling and other permits or approvals and rights-of-way in a timely manner (or at all), which may be negatively impacted by the impact of COVID-19 restrictions on regulatory employees who process and approve permits, other approvals and rights-of-way and which may be restricted by new Presidential and Secretarial orders and regulation and legislation;

•risks related to litigation; and

•cybersecurity threats, technology system failures and data security issues.

All forward-looking statements speak only as of the date of this Quarterly Report. You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make. Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Quarterly Report are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied by the forward-looking statements.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and the price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

Part I- Financial Information

Item 1. Financial Statements


Riley Exploration Permian, Inc.
Condensed Consolidated Balance Sheets
($ in thousands)
(unaudited)
	March 31, 2021		September 30, 2020

Assets
Current Assets:
Cash and cash equivalents	$	10,062	$	1,660
Accounts receivable	13,605		10,128
Accounts receivable – related parties	177		55

Prepaid expenses and other current assets	2,919		1,752
Current derivative assets	352		18,819
Current assets - discontinued operations	103		0
Total Current Assets	27,218		32,414

Non-Current Assets:
Oil and natural gas properties, net (successful efforts)	319,816		310,726
Other property and equipment, net	2,080		1,801

Non-current derivative assets	564		3,102
Other non-current assets, net	2,442		2,949


Noncurrent assets - discontinued operations	5,066		0
Total Non-Current Assets	329,968		318,578

Total Assets	$	357,186	$	350,992



Riley Exploration Permian, Inc.
Condensed Consolidated Balance Sheets - (Continued)
($ in thousands)
(unaudited)
	March 31, 2021		September 30, 2020

Liabilities, Series A Preferred Units, and Members'/Shareholders' Equity
Current Liabilities:
Accounts payable	$	6,335	$	4,739

Income taxes payable	1,129		0
Accrued liabilities	26,499		8,746

Revenue payable	7,685		4,432
Advances from joint interest owners	274		254


Current derivative liabilities	14,310		0
Other current liabilities	469		392
Current liabilities - discontinued operations	95		0
Total Current Liabilities	56,796		18,563

Non-Current Liabilities:
Non-current derivative liabilities	6,076		0
Asset retirement obligations	2,270		2,268

Revolving credit facility	97,500		101,000
Deferred tax liabilities	11,589		1,834

Other non-current liabilities	108		418
Noncurrent liabilities - discontinued operations	1,607		0
Total Non-Current Liabilities	119,150		105,520

Total Liabilities	175,946		124,083

Series A Preferred Units	0		60,292

Commitments and Contingencies (Note 17)	0		0

Members' Equity	0		166,617

Shareholders' Equity:
Preferred stock, $0.0001 par value, 25,000,000 shares designated; 0 shares issued and outstanding	0		—
Common stock, $0.001 par value, authorized 240,000,000 shares; 17,825,179 and 0 shares issued and outstanding, respectively	18		—
Additional paid-in capital	218,974		—
Accumulated deficit	(37,752)		—
Total Shareholders' Equity	181,240		—

Total Liabilities, Series A Preferred Units, and Members'/Shareholders' Equity	$	357,186	$	350,992

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


Riley Exploration Permian, Inc.
Condensed Consolidated Statements of Operations
($ in thousands, except per share/unit amounts)
(unaudited)
	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020

Revenues:
Oil and natural gas sales, net	$	36,659	$	24,356	$	59,073	$	52,855
Contract services – related parties	600		1,050		1,200		2,100
Total Revenues	37,259		25,406		60,273		54,955

Costs and Expenses:
Lease operating expenses	6,773		6,028		11,569		11,757
Production taxes	1,937		1,156		2,998		2,515
Exploration costs	5,473		1,747		5,897		2,474
Depletion, depreciation, amortization and accretion	6,251		5,357		12,241		10,992
General and administrative:
Administrative costs	2,696		3,514		5,141		6,733
Unit-based compensation expense	276		206		689		359
Stock-based compensation expense	4,571		0		4,571		0
Cost of contract services - related parties	91		138		239		306
Transaction costs	2,164		28		3,213		27
Total Costs and Expenses	30,232		18,174		46,558		35,163

Income From Operations	7,027		7,232		13,715		19,792

Other Income (Expense):
Interest expense	(1,165)		(1,418)		(2,400)		(2,784)
Gain (loss) on derivatives	(24,903)		69,239		(38,812)		51,204
Total Other Income (Expense)	(26,068)		67,821		(41,212)		48,420

Net Income (Loss) From Continuing Operations Before Income Taxes	(19,041)		75,053		(27,497)		68,212

Income tax expense	(14,231)		0		(13,716)		0
Net Income (Loss) From Continuing Operations	(33,272)		75,053		(41,213)		68,212

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


Riley Exploration Permian, Inc.
Condensed Consolidated Statements of Operations - (Continued)
($ in thousands, except per share/unit amounts)
(unaudited)
	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
Discontinued Operations:
Loss from discontinued operations	(18,631)		0		(18,631)		0
Income tax benefit on discontinued operations	25		0		25		0
Loss on discontinued operations	(18,606)		0		(18,606)		0

Net Income (Loss)	(51,878)		75,053		(59,819)		68,212

Dividends on preferred units	(574)		(877)		(1,491)		(1,741)
Net Income (Loss) Attributable to Common Shareholders/Unitholders	$	(52,452)	$	74,176	$	(61,310)	$	66,471

Net Income (Loss) per Share/Unit from Continuing Operations:
Basic	$	(2.33)	$	5.95	$	(3.15)	$	5.34
Diluted	$	(2.33)	$	4.55	$	(3.15)	$	4.15

Net Income (Loss) per Share/Unit from Discontinued Operations:
Basic	$	(1.28)	$	0	$	(1.37)	$	0
Diluted	$	(1.28)	$	0	$	(1.37)	$	0

Net Income (Loss) per Share/Unit:
Basic	$	(3.61)	$	5.95	$	(4.52)	$	5.34
Diluted	$	(3.61)	$	4.55	$	(4.52)	$	4.15

Weighted Average Common Share/Units Outstanding:
Basic	14,542		12,457		13,575		12,446
Diluted	14,542		16,486		13,575		16,435

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


Riley Exploration Permian, Inc.
Condensed Consolidated Statements of Changes in Members'/Shareholders' Equity
($, units and shares in thousands)
(unaudited)
	Members' Equity			Shareholders' Equity
				Common Stock
	Units Outstanding	Amount		Shares	Amount		Additional Paid-in Capital		Accumulated Deficit		Total Shareholders' Equity
For the Six Months Ended March 31, 2020

Balance, September 30, 2019	1,527	$	149,383	—	$	—	$	—	$	—	$	—
Issuance of common units under long-term incentive plan	15	—		—	—		—		—		—
Purchase of common units under long-term incentive plan	(2)	(194)		—	—		—		—		—
Dividends on preferred units	—	(864)		—	—		—		—		—
Dividends on common units	—	(4,997)		—	—		—		—		—
Unit-based compensation expense	—	153		—	—		—		—		—
Net loss	—	(6,841)		—	—		—		—		—
Balance, December 31, 2019	1,540	$	136,640	—	$	—	$	—	$	—	$	—
Issuance of common units under long-term incentive plan	16	—		—	—		—		—		—
Purchase of common units under long-term incentive plan	(1)	(124)		—	—		—		—		—
Dividends on preferred units	—	(877)		—	—		—		—		—
Dividends on common units	—	(4,988)		—	—		—		—		—
Unit-based compensation expense	—	206		—	—		—		—		—
Net income	—	75,053		—	—		—		—		—
Balance, March 31, 2020	1,555	$	205,910	—	$	—	$	—	$	—	$	—

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


Riley Exploration Permian, Inc.
Condensed Consolidated Statements of Changes in Members'/Shareholders' Equity - (Continued)
($, units and shares in thousands)
(unaudited)
	Members' Equity			Shareholders' Equity
				Common Stock
	Units Outstanding	Amount		Shares	Amount		Additional Paid-in Capital		Accumulated Deficit		Total Shareholders' Equity
For the Six Months Ended March 31, 2021

Balance, September 30, 2020	1,555	$	166,617	—	$	—	$	—	$	—	$	0
Issuance of common units under long-term incentive plan	13	—		—	—		—		—		—
Dividends on preferred units	—	(917)		—	—		—		—		0
Dividends on common units	—	(3,801)		—	—		—		—		0
Unit-based compensation expense	—	413		—	—		—		—		0
Net loss	—	(7,941)		—	—		—		—		0
Balance, December 31, 2020	1,568	$	154,371	—	$	—	$	—	$	—	$	0
Purchase of common units under long-term incentive plan	(3)	(191)		—	—		—		—		0
Dividends on preferred units	—	(574)		—	—		—		—		0
Preferred units converted to common units	512	61,196		—	—		—		—		0
Dividends on common units	—	(3,770)		—	—		—		—		0
Unit-based compensation expense	—	276		—	—		—		—		0
Net loss from January 1, 2021 through February 26, 2021	—	(19,117)		—	—		—		—		0
Restricted common shares issued in exchange for common units issued under long-term incentive plan	(24)	—		198	—		—		—		—
Common shares issued in exchange for common units (effected for 1-for-12 reverse stock split	(2,053)	(192,191)		16,733	17		192,174		—		192,191
Common shares issued for business combination	—	—		891	1		26,391		—		26,392
Restricted common shares issued	—	—		3	—		—		—		—
Share-based compensation expense	—	—		—	—		409		—		409
Cash dividends declared ($0.28 per share)	—	—		—	—		—		(4,991)		(4,991)
Net loss from February 27, 2021 through March 31, 2021	—	—		—	—		—		(32,761)		(32,761)
Balance, March 31, 2021	0	$	0	17,825	$	18	$	218,974	$	(37,752)	$	181,240

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


Riley Exploration Permian, Inc.
Condensed Consolidated Statements of Cash Flows
($ in thousands)
(unaudited)
	Six Months Ended March 31,
	2021		2020

Cash Flows from Operating Activities:
Net income (loss)	$	(59,819)	$	68,212

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Non-cash discontinued operations	18,606		0
Oil and gas lease expirations	5,827		547
Depletion, depreciation, amortization and accretion	12,241		10,992


(Gain) Loss on derivatives	38,812		(51,204)
Settlements on derivative contracts	2,579		5,492
Amortization of deferred financing costs	316		318

Unit-based compensation expense	689		359
Stock-based compensation expense	4,571		0
Deferred income tax expense	12,938		0

Changes in operating assets and liabilities:
Accounts receivable	(3,477)		1,528
Accounts receivable – related parties	(122)		(1,247)
Prepaid expenses and other current assets	(433)		1,133
Other non-current assets	1		35
Accounts payable and accrued liabilities	1,366		(2,617)

Income taxes payable	778		0
Revenue payable	3,253		951
Advances from joint interest owners	20		1,091
Advances from related parties	0		662
Net Cash Provided By Operating Activities - Continuing Operations	38,146		36,252

Cash Flows From Investing Activities:
Additions to oil and natural gas properties	(17,133)		(33,712)
Acquisition of oil and natural gas properties	(171)		(3,976)
Additions to other property and equipment	(380)		(53)
Tengasco acquired cash	859		0
Net Cash Used In Investing Activities - Continuing Operations	(16,825)		(37,741)

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


Riley Exploration Permian, Inc.
Condensed Consolidated Statements of Cash Flows – (Continued)
($ in thousands)
(unaudited)
	Six Months Ended March 31,
	2021		2020

Cash Flows From Financing Activities:

Deferred financing costs	(129)		(267)

Proceeds from revolving credit facility	5,500		14,000
Repayment under revolving credit facility	(9,000)		(2,000)

Payment of common unit dividends	(7,841)		(10,347)
Payment of preferred unit dividends	(1,491)		0
Purchase of common units under long-term incentive plan	(191)		(318)
Net Cash Provided by (Used In) Financing Activities - Continuing Operations	(13,152)		1,068

Net Increase (Decrease) in Cash and Cash Equivalents from Continuing Operations	8,169		(421)

Cash Flows from Discontinued Operations:
Operating activities	238		0

Financing activities	(5)		0
Net Increase in Cash and Cash Equivalents from Discontinued Operations	233		0

Net Increase (Decrease) in Cash and Cash Equivalents	8,402		(421)

Cash and Cash Equivalents, Beginning of Period	1,660		3,726
Cash and Cash Equivalents, End of Period	$	10,062	$	3,305

Supplemental Disclosure of Cash Flow Information

Cash Paid For:
Interest	$	1,856	$	2,396

Non-cash Investing and Financing Activities - Continuing Operations:
Changes in capital expenditures in accounts payable and accrued liabilities	$	9,471	$	5,027
Common unit dividends incurred but not paid	$	84	$	25
Asset retirement obligations	$	53	$	859

Preferred unit dividends paid in kind	$	904	$	1,715
Preferred unit dividends	$	0	$	1,741
Dividends declared on common shares	$	4,991	$	0
Common stock issued in exchange for common units	$	192,191	$	0
Assets acquired and liabilities assumed in business combination	$	3,497	$	0
Common stock issued for business combination	$	26,392	$	0
Preferred units converted to common units	$	61,196	$	0

Non-cash Investing and Financing Activities - Discontinued Operations:
Goodwill incurred in business combination	$	19,057	$	0
Assets acquired and liabilities assumed for business combination	$	2,978	$	0

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

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1.Nature of Business

Riley Exploration Permian, Inc. ("Riley Permian", "REPX", "the Company", "Registrant", "we", "our", or "us") is a growth-oriented, independent oil and natural gas company focused on growing our conventional reserves, production and cash flow per share 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 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 with additional acreage located in Lea and Roosevelt Counties, New Mexico.

On February 26, 2021 (the “Closing Date”), Riley Exploration Permian, Inc., a Delaware corporation (f/k/a Tengasco, Inc. (“Tengasco”)), consummated the previously announced merger pursuant to that certain Agreement and Plan of Merger (“Merger Agreement”), dated as of October 21, 2020, by and among Tengasco, Antman Sub, LLC, a newly formed Delaware limited liability company and wholly owned subsidiary of Tengasco (“Merger Sub”), and Riley Exploration – Permian, LLC (“REP LLC”), as amended by Amendment No. 1 to Agreement and Plan of Merger, dated as of January 20, 2021, by and among Tengasco, Merger Sub and REP LLC. Pursuant to the terms of the Merger Agreement, Merger Sub merged with and into REP LLC, with REP LLC surviving as the surviving company and as a wholly-owned subsidiary of Tengasco (collectively, with the other transactions described in the Merger Agreement, the “Merger”). On the Closing Date, the Registrant changed its name from Tengasco, Inc. to Riley Exploration Permian, Inc. Our organizational structure includes wholly-owned consolidated subsidiaries through which our operations are conducted.

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, 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 significantly reduced global economic activity, resulting in a significant decline in the demand for oil and other commodities. These factors caused a swift and material deterioration in commodity prices for a majority of 2020, which significantly impacted our revenues for the three and six months ended March 31, 2020. However, near the end of 2020 and the beginning of 2021, oil prices steadily increased but are expected to continue to be volatile as these events evolve. The Company cannot estimate the full length or gravity of the future impacts at this time and if there is another significant decline in oil price, it could have a material adverse effect on the Company’s results of operations, financial position, liquidity and the value of oil and natural gas reserves.

CARES Act and Consolidated Appropriations Act

On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief and Economic Security Act ("CARES Act"), and on December 27, 2020, President Trump signed into law the Consolidated Appropriations Act. These Acts are meant to provide fast and direct economic assistance for American workers, families, and small businesses, and preserve jobs for American industries. 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 and the Consolidated Appropriations Act.

2. Basis of Presentation

These unaudited condensed consolidated financial statements as of March 31, 2021 and for the three and six months ended March 31, 2021 and 2020 include the accounts of Riley Permian and its wholly-owned subsidiaries REP LLC, Riley Permian Operating Company, LLC ("RPOC"), Riley Employee Member, LLC ("REM"), Tengasco Pipeline Corporation ("TPC"), Tennessee Land & Mineral Corporation ("TLMC"), and Manufactured Methane Corporation ("MMC"). All intercompany balances and transactions have been eliminated upon consolidation. The Merger was accounted for as a reverse merger. The historical operations of REP LLC are deemed to be those of the Company. Thus, the consolidated financial statements included in this report reflect (i) the historical operating results of REP LLC prior to the Transaction;

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

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

(ii) the consolidated results of the Company following the Merger; (iii) the assets and liabilities of REP LLC at their historical cost; and (iv) the Company’s equity and earnings per share for all periods presented.

Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States ("U.S. GAAP") have been condensed or omitted pursuant to the rules and regulation of the Securities and Exchange Commission. These condensed consolidated financial statements should be read in conjunction with REP LLC's audited consolidated financial statements and related notes for the year ended September 30, 2020, included in the Company's current report on Form 8-K/A filed on April 22, 2021.

These condensed consolidated financial statements include all adjustments, consisting of normal recurring adjustments, that are, in the ~~accounts~~opinion of the ~~Company and its wholly owned subsidiaries after elimination~~Company's management, necessary for a fair presentation of ~~all significant intercompany transactions and balances.~~

~~Use of Estimates~~

~~The accompanying~~the results for the interim periods. These condensed consolidated financial statements are ~~prepared~~not necessarily indicative of the results for the entire fiscal year.

3.Summary of Significant Accounting Policies

Significant Estimates

The preparation of financial statements in conformity with U.S. GAAP ~~which require~~requires management to make estimates and assumptions that affect the amounts reported ~~amounts~~in the condensed consolidated financial statements and accompanying condensed notes. These estimates and assumptions may also affect disclosure of contingent assets and liabilities atas of the ~~dates~~date of the financial statements and the reported amounts of revenues and expenses during the reporting ~~periods.~~period.

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, ~~reserve quantities~~but are not limited to, estimates of proved oil and ~~estimated~~natural gas reserves and related present value estimates of future net cash flows ~~associated with proved reserves, which significantly impact depletion expense and potential impairments~~therefrom, the carrying value of oil and natural gas properties, ~~income taxes~~accounts receivable and accrued operating expenses, the fair value determination of acquired assets and assumed liabilities, certain tax accruals and the ~~valuation~~fair value of ~~deferred tax~~derivatives.

Accounts Receivable

The Company had 0 allowance for doubtful accounts at March 31, 2021 and September 30, 2020.

Accounts receivable is summarized below:


	March 31, 2021		September 30, 2020

	($ in thousands)
Oil, natural gas and NGL sales	$	12,990	$	6,919
Joint interest accounts receivable	557		1,022
Realized derivative receivable	0		2,187
Other accounts receivable	58		0
Total accounts receivable	$	13,605	$	10,128

Business Combinations

In accordance with ASC 805 - Business Combinations (“ASC 805”), the Company accounts for its acquisitions that qualify as a business using the acquisition method under ASC 805. If the set of assets ~~stock-based compensation,~~ and ~~commitments~~activities is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the acquisition, including certain transaction costs, is allocated to the assets acquired on the basis of relative fair values.

The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method under ASC 805, the Company allocates the purchase price of an acquired business to its identifiable assets and ~~contingencies. We analyze our estimates~~liabilities based on ~~historical experience~~the estimated fair values. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and ~~various other assumptions that we believe to be reasonable. While we believe that our estimates~~liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and ~~assumptions used~~liabilities acquired over the purchase price of an acquired business is recorded as a bargain purchase gain.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Accrued Liabilities

Accrued liabilities consisted of the following:


	March 31, 2021		September 30, 2020

	($ in thousands)
Accrued capital expenditures	$	12,215	$	2,964
Accrued lease operating expenses	2,249		1,617
Accrued ad valorem tax	365		680
Accrued general and administrative costs	2,151		2,125
Accrued interest expense	28		63
Accrued dividends on preferred units	0		903
Accrued dividends on common units	0		95
Accrued dividends on common shares	4,991		0
Accrued stock-based compensation liability	4,162		0
Other accrued expenditures	338		299
Total accrued liabilities	$	26,499	$	8,746

Asset Retirement Obligations

Components of the changes in ~~preparation of~~asset retirement obligations ("ARO") for the six months ended March 31, 2021 and year ended September 30, 2020 are shown below:


	March 31, 2021		September 30, 2020
	($ in thousands)
ARO, beginning balance	$	2,326	$	1,203
Liabilities incurred	53		68
Liabilities acquired	0		1,161
Revision of estimated obligations	0		(45)
Liability settlements and disposals	0		(131)
Accretion	43		70
ARO, ending balance	2,422		2,326
Less: current ARO	(152)		(58)
ARO, long-term	$	2,270	$	2,268

Current ARO is included within accrued liabilities on the condensed consolidated ~~financial statements~~balance sheets.

Goodwill

Goodwill represents the future economic benefit arising from other assets acquired in a business combination that are ~~appropriate, actual results could differ~~not individually identified or separately recognized. Goodwill is initially recognized as the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment annually in accordance with ASC 350 - Intangibles - Goodwill and Other ("ASC 350"), or more frequently if there is a change in events or circumstances that indicate the carrying value of the goodwill may not be recoverable.

The Company recognized goodwill of $19.1 million from ~~those estimates~~the Merger. The Company assessed the oil and ~~assumptions.~~natural gas properties acquired through the Merger as a separate reporting unit (the "Kansas Reporting Unit") and therefore allocated the full goodwill amount to the Kansas Reporting Unit. In March 2021, the Company entered into an agreement to divest the Kansas Reporting Unit which is made up primarily of the oil and natural gas properties acquired, which includes producing oil wells, shut-in wells, temporarily abandoned wells, and active disposal wells (the "Kansas Properties"). The Company did not fully integrate the Kansas Reporting Unit into the Company's operations since it was deemed to be held for sale upon acquisition. See further discussion in Note 4 - Business Combinations.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

In accordance with ASC 350, the impairment test should occur at the reporting unit level determined by the Company and an impairment should only exist if the Company has determined the carrying value of the goodwill no longer exceeds the implied fair value. A two-step goodwill impairment test should be used to identify potential goodwill impairment and measure such impairment, if any. The first step is a qualitative assessment which the Company will determine whether it is more likely than not (greater than 50 percent likelihood) that the fair value of the reporting unit is less than its carrying value, including goodwill. If the Company determines it is more likely than not the fair value of the reporting unit is less than its carrying value, including goodwill, then step two is a quantitative assessment. The quantitative assessment compares the implied fair value of the reporting unit goodwill with the carrying value of the goodwill. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

The Company assessed the goodwill balance as of March 31, 2021 for impairment because the Company entered into a Purchase and Sale Agreement ("PSA") on March 10, 2021 for $3.5 million before closing adjustments. See further discussion in Note 15 - Discontinued Operations and Assets Held for Sale. As of March 31, 2021, the Kansas Reporting Unit was recorded at a fair value of $4.6 million using a discounted cash flow method of valuation in accordance with ASC 805. The carrying value of the Kansas Reporting Unit was $22.0 million, which includes a goodwill balance of $19.1 million. The Company concluded the fair value of the Kansas Reporting Unit was $3.5 million in accordance with ASC 350 since the Company entered into a PSA shortly after the Kansas Reporting Unit was deemed held for sale. The carrying value exceeded the implied fair value at the time of the closing of the Merger. As such, the Company concluded the goodwill balance associated with the Kansas Reporting Unit was impaired and recognized a goodwill impairment loss, included within loss from discontinued operations, of $18.5 million for the period ending March 31, 2021.

~~Revenue Recognition~~

Accounts Receivable

The Company ~~identifies~~had 0 allowance for doubtful accounts at March 31, 2021 and September 30, 2020.

Accounts receivable is summarized below:


	March 31, 2021		September 30, 2020

	($ in thousands)
Oil, natural gas and NGL sales	$	12,990	$	6,919
Joint interest accounts receivable	557		1,022
Realized derivative receivable	0		2,187
Other accounts receivable	58		0
Total accounts receivable	$	13,605	$	10,128

Business Combinations

In accordance with ASC 805 - Business Combinations (“ASC 805”), the ~~contracts with each~~Company accounts for its acquisitions that qualify as a business using the acquisition method under ASC 805. If the set of ~~its customers~~assets and activities is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the ~~separate performance obligations associated with each of these contracts. Revenues are recognized when~~cost accumulation model, the performance obligations are satisfied and when control of goods or services are transferred to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services.

Crude oil is sold on a month-to-month contract at a price based on an index price from the purchaser, net of differentials. Crude oil that is produced is stored in storage tanks. The Company will contact the purchaser and request it to pick up the crude oil from the storage tanks. When the purchaser picks up the crude from the storage tanks, controlcost of the ~~crude transfers~~acquisition, including certain transaction costs, is allocated to the ~~purchaser,~~assets acquired on the ~~Company’s contractual obligation is satisfied, and revenues are recognized. The sales~~basis of oil represent the Company’s share of revenues net of royalties and excluding revenue interests owned by others. When selling oil on behalf of royalty owners or working interest owners, the Company is acting as an agent and thus reports revenues on a net basis to the Company. Fees and other deductions incurred prior to transfer of control are recorded as production costs. Revenues are reported net of fees and other deductions incurred after transfer of control.

relative fair values.

The Company ~~operates certain salt water disposal wells, some~~includes the results of ~~which accept water from third parties. The contracts~~operations of acquired businesses beginning on the respective acquisition dates. In accordance with the ~~third parties primarily require a flat monthly fee for~~acquisition method under ASC 805, the ~~third parties~~Company allocates the purchase price of an acquired business to ~~dispose water into~~its identifiable assets and liabilities based on the ~~wells. In some cases, the contract~~estimated fair values. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business is recorded as a per barrel charge to dispose water into the wells. There is no requirement under the contracts for these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells during a given month, the Company has met its contractual obligations and revenues are recognized for that month.

bargain purchase gain.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

~~Table of Contents~~(Unaudited)

~~Tengasco, Inc. and Subsidiaries~~Accrued Liabilities

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

Accrued liabilities consisted of the following:


	March 31, 2021		September 30, 2020

	($ in thousands)
Accrued capital expenditures	$	12,215	$	2,964
Accrued lease operating expenses	2,249		1,617
Accrued ad valorem tax	365		680
Accrued general and administrative costs	2,151		2,125
Accrued interest expense	28		63
Accrued dividends on preferred units	0		903
Accrued dividends on common units	0		95
Accrued dividends on common shares	4,991		0
Accrued stock-based compensation liability	4,162		0
Other accrued expenditures	338		299
Total accrued liabilities	$	26,499	$	8,746

Asset Retirement Obligations

~~The following table presents~~Components of the ~~disaggregated revenue by commodity~~changes in asset retirement obligations ("ARO") for the ~~three~~six months ended March 31, 2021 and ~~nine months~~year ended September 30, 2020 ~~and 2019~~ (are shown below:


	March 31, 2021		September 30, 2020
	($ in thousands)
ARO, beginning balance	$	2,326	$	1,203
Liabilities incurred	53		68
Liabilities acquired	0		1,161
Revision of estimated obligations	0		(45)
Liability settlements and disposals	0		(131)
Accretion	43		70
ARO, ending balance	2,422		2,326
Less: current ARO	(152)		(58)
ARO, long-term	$	2,270	$	2,268

Current ARO is included within accrued liabilities on the condensed consolidated balance sheets.

Goodwill

Goodwill represents the future economic benefit arising from other assets acquired in ~~thousands)~~:

For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,

2020 2019 2020 2019

Crude oil
$
757

$
1,208

$
2,275

$
3,757

Saltwater disposal fees
8

7

17

20

Total
$
765

$
1,215

$
2,292

$
3,777

~~There were no natural gas imbalances at September 30, 2020~~a business combination that are not individually identified or ~~December 31, 2019.~~

~~Cash and Cash Equivalents~~

~~Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase.~~

~~Inventory~~

~~Inventory consists of crude oil in tanks and~~separately recognized. Goodwill is ~~carried at lower of cost or market value. The cost value component~~initially recognized as the excess of the ~~oil inventory is calculated using~~purchase price of a business combination over the average cost per barrel for the three months ended September 30, 2020 and December 31, 2019. These costs include production costs and taxes. The market value component is calculated using the average September 30, 2020 and December 2019 oil sales prices received by the Company. At September 30, 2020 and December 31, 2019, the cost component was used to value oil inventory. At September 30, 2020 and December 31, 2019, inventory consisted of the following ~~(in thousands)~~:

September 30,
2020

December 31,
2019

Oil – carried at lower of cost or market
$
302

$
415

Total inventory
$
302

$
415

~~Full Cost Method of Accounting~~

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic related costs, certain internal exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not already included, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since 2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had $0 in unevaluated properties as of September 30, 2020 and at December 31, 2019. Proceeds from the sale of oil and gas properties are accounted for as reductions to capitalized costs unless such sales cause a significant change in the relationship between costs and the estimated value of proved reserves, in which case a gain or loss is recognized.

~~At the end of each reporting period, the Company performs a “ceiling test” on the~~fair value of the net ~~capitalized cost of oil~~assets acquired and ~~gas properties. This test compares the net capitalized cost (capitalized cost of oil~~is tested for impairment annually in accordance with ASC 350 - Intangibles - Goodwill and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of costOther ("ASC 350"), or ~~estimated fair value of unproven properties included~~more frequently if there is a change in ~~the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down~~events or ~~impairment is required. A write-down of~~circumstances that indicate the carrying value of the ~~asset is a non-cash charge that reduces earnings in the current period. Once incurred, a write-down~~goodwill may not be ~~reversed in~~recoverable.

The Company recognized goodwill of $19.1 million from the Merger. The Company assessed the oil and natural gas properties acquired through the Merger as a ~~later period.~~separate reporting unit (the "Kansas Reporting Unit") and therefore allocated the full goodwill amount to the Kansas Reporting Unit. In March 2021, the Company entered into an agreement to divest the Kansas Reporting Unit which is made up primarily of the oil and natural gas properties acquired, which includes producing oil wells, shut-in wells, temporarily abandoned wells, and active disposal wells (the "Kansas Properties"). The Company did not ~~record any~~fully integrate the Kansas Reporting Unit into the Company's operations since it was deemed to be held for sale upon acquisition. See further discussion in Note 4 - Business Combinations.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

In accordance with ASC 350, the impairment test should occur at the reporting unit level determined by the Company and an impairment should only exist if the Company has determined the carrying value of the goodwill no longer exceeds the implied fair value. A two-step goodwill impairment test should be used to identify potential goodwill impairment and measure such impairment, if any. The first step is a qualitative assessment which the Company will determine whether it is more likely than not (greater than 50 percent likelihood) that the fair value of the reporting unit is less than its ~~oil~~carrying value, including goodwill. If the Company determines it is more likely than not the fair value of the reporting unit is less than its carrying value, including goodwill, then step two is a quantitative assessment. The quantitative assessment compares the implied fair value of the reporting unit goodwill with the carrying value of the goodwill. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

The Company assessed the goodwill balance as of March 31, 2021 for impairment because the Company entered into a Purchase and ~~gas properties during~~Sale Agreement ("PSA") on March 10, 2021 for $3.5 million before closing adjustments. See further discussion in Note 15 - Discontinued Operations and Assets Held for Sale. As of March 31, 2021, the ~~nine months ended September 30, 2020~~Kansas Reporting Unit was recorded at a fair value of $4.6 million using a discounted cash flow method of valuation in accordance with ASC 805. The carrying value of the Kansas Reporting Unit was $22.0 million, which includes a goodwill balance of $19.1 million. The Company concluded the fair value of the Kansas Reporting Unit was $3.5 million in accordance with ASC 350 since the Company entered into a PSA shortly after the Kansas Reporting Unit was deemed held for sale. The carrying value exceeded the implied fair value at the time of the closing of the Merger. As such, the Company concluded the goodwill balance associated with the Kansas Reporting Unit was impaired and ~~2019.~~recognized a goodwill impairment loss, included within loss from discontinued operations, of $18.5 million for the period ending March 31, 2021.

Accounts Receivable

The Company had 0 allowance for doubtful accounts at March 31, 2021 and September 30, 2020.

Accounts receivable ~~consist~~is summarized below:


	March 31, 2021		September 30, 2020

	($ in thousands)
Oil, natural gas and NGL sales	$	12,990	$	6,919
Joint interest accounts receivable	557		1,022
Realized derivative receivable	0		2,187
Other accounts receivable	58		0
Total accounts receivable	$	13,605	$	10,128

Business Combinations

In accordance with ASC 805 - Business Combinations (“ASC 805”), the Company accounts for its acquisitions that qualify as a business using the acquisition method under ASC 805. If the set of ~~uncollateralized joint interest owner obligations due within 30 days~~assets and activities is not considered a business, it is accounted for as an asset acquisition using a cost accumulation model. In the cost accumulation model, the cost of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of sales of oil and gas production, and other miscellaneous receivables. No interestacquisition, including certain transaction costs, is ~~charged on past-due balances. Payments made on accounts receivable are applied first~~allocated to the ~~earliest unpaid items. We review accounts receivable periodically~~assets acquired on the basis of relative fair values.

The Company includes the results of operations of acquired businesses beginning on the respective acquisition dates. In accordance with the acquisition method under ASC 805, the Company allocates the purchase price of an acquired business to its identifiable assets and ~~reduce~~liabilities based on the estimated fair values. This fair value measurement is based on unobservable (Level 3) inputs. The excess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. The excess value of the net identifiable assets and liabilities acquired over the purchase price of an acquired business is recorded as a bargain purchase gain.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Accrued Liabilities

Accrued liabilities consisted of the following:


	March 31, 2021		September 30, 2020

	($ in thousands)
Accrued capital expenditures	$	12,215	$	2,964
Accrued lease operating expenses	2,249		1,617
Accrued ad valorem tax	365		680
Accrued general and administrative costs	2,151		2,125
Accrued interest expense	28		63
Accrued dividends on preferred units	0		903
Accrued dividends on common units	0		95
Accrued dividends on common shares	4,991		0
Accrued stock-based compensation liability	4,162		0
Other accrued expenditures	338		299
Total accrued liabilities	$	26,499	$	8,746

Asset Retirement Obligations

Components of the changes in asset retirement obligations ("ARO") for the six months ended March 31, 2021 and year ended September 30, 2020 are shown below:


	March 31, 2021		September 30, 2020
	($ in thousands)
ARO, beginning balance	$	2,326	$	1,203
Liabilities incurred	53		68
Liabilities acquired	0		1,161
Revision of estimated obligations	0		(45)
Liability settlements and disposals	0		(131)
Accretion	43		70
ARO, ending balance	2,422		2,326
Less: current ARO	(152)		(58)
ARO, long-term	$	2,270	$	2,268

Current ARO is included within accrued liabilities on the condensed consolidated balance sheets.

Goodwill

Goodwill represents the future economic benefit arising from other assets acquired in a business combination that are not individually identified or separately recognized. Goodwill is initially recognized as the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment annually in accordance with ASC 350 - Intangibles - Goodwill and Other ("ASC 350"), or more frequently if there is a change in events or circumstances that indicate the carrying ~~amount by a valuation allowance that reflects our best estimate~~value of the ~~amount that~~goodwill may not be ~~collectible. There~~recoverable.

The Company recognized goodwill of $19.1 million from the Merger. The Company assessed the oil and natural gas properties acquired through the Merger as a separate reporting unit (the "Kansas Reporting Unit") and therefore allocated the full goodwill amount to the Kansas Reporting Unit. In March 2021, the Company entered into an agreement to divest the Kansas Reporting Unit which is made up primarily of the oil and natural gas properties acquired, which includes producing oil wells, shut-in wells, temporarily abandoned wells, and active disposal wells (the "Kansas Properties"). The Company did not fully integrate the Kansas Reporting Unit into the Company's operations since it was deemed to be held for sale upon acquisition. See further discussion in Note 4 - Business Combinations.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

In accordance with ASC 350, the impairment test should occur at the reporting unit level determined by the Company and an impairment should only exist if the Company has determined the carrying value of the goodwill no ~~allowance~~longer exceeds the implied fair value. A two-step goodwill impairment test should be used to identify potential goodwill impairment and measure such impairment, if any. The first step is a qualitative assessment which the Company will determine whether it is more likely than not (greater than 50 percent likelihood) that the fair value of the reporting unit is less than its carrying value, including goodwill. If the Company determines it is more likely than not the fair value of the reporting unit is less than its carrying value, including goodwill, then step two is a quantitative assessment. The quantitative assessment compares the implied fair value of the reporting unit goodwill with the carrying value of the goodwill. An impairment loss is recognized if the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill.

The Company assessed the goodwill balance as of March 31, 2021 for impairment because the Company entered into a Purchase and Sale Agreement ("PSA") on March 10, 2021 for $3.5 million before closing adjustments. See further discussion in Note 15 - Discontinued Operations and Assets Held for Sale. As of March 31, 2021, the Kansas Reporting Unit was recorded at ~~September 30, 2020 or December~~a fair value of $4.6 million using a discounted cash flow method of valuation in accordance with ASC 805. The carrying value of the Kansas Reporting Unit was $22.0 million, which includes a goodwill balance of $19.1 million. The Company concluded the fair value of the Kansas Reporting Unit was $3.5 million in accordance with ASC 350 since the Company entered into a PSA shortly after the Kansas Reporting Unit was deemed held for sale. The carrying value exceeded the implied fair value at the time of the closing of the Merger. As such, the Company concluded the goodwill balance associated with the Kansas Reporting Unit was impaired and recognized a goodwill impairment loss, included within loss from discontinued operations, of $18.5 million for the period ending March 31, ~~2019.~~2021.

Revenue Recognition

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

The following table ~~sets forth information concerning~~presents oil and natural gas sales from continuing operations disaggregated by product:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)
Oil and natural gas sales:
Oil	$	30,784	$	24,598	$	52,891	$	53,396
Natural gas	4,516		(93)		4,635		(271)
Natural gas liquids	1,359		(149)		1,547��		(270)
Total oil and natural gas sales, net	$	36,659	$	24,356	$	59,073	$	52,855

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

Transaction Costs


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)				($ in thousands)
Business combination acquisition costs	$	2,164	$	28	$	3,053	$	27
Other	0		0		160		0
Total transaction costs	$	2,164	$	28	$	3,213	$	27

The Company recognized transaction costs of $2.2 million and $3.2 million for the ~~Company’s accounts receivable~~ (three and six months ended March 31, 2021. These costs relate to the fees incurred for the Merger. See further discussion in ~~thousands)~~:Note 4 - Business Combinations.

September 30,
2020

December 31,
2019

Revenue
$
259

$
415

Tax
—

65

Joint interest
3

77

Accounts receivable - current
$
262

$
557

Tax - noncurrent
$
—

$
65

Income Taxes

~~At December 31, 2019,~~Upon closing of the Merger on February 26, 2021, Tengasco was renamed to Riley Exploration Permian, Inc. and REP LLC became a wholly-owned subsidiary of Riley Permian, the consolidated company, which is subject to current federal and state income taxes, including Texas Margin Tax. See further discussion in Note 4 - Business Combinations. The Company recorded a ~~tax related current receivable~~provision for federal and state income taxes as of ~~$65,000~~March 31, 2021. See further discussion in Note 14 - Income Taxes.

Riley Permian uses the asset and ~~a tax related noncurrent receivable~~liability method of ~~$65,000. In September 2020, the Company received a tax refund of approximately $130,000 associated with the current and noncurrent tax receivables that existed at December 31, 2019.~~

On March 27, 2020, the Coronavirus Aid, Relief and Economic Security Act (“CARES” Act) was enacted in response to the COVID-19 pandemic. The CARES Act, among other things, accelerated the Company’s ability to recover refundable alternative minimum tax (“AMT”) credits to 2018 and 2019. As a result, the Company has reclassified the $65,000 of the remaining noncurrent AMT credit carryforwards from a noncurrent receivable to a current receivable. The Company requested a refund of these AMT credits when it filed its 2019 tax return and received this refund in September 2020. (See Note (2) Income Taxes)

~~(2) Income Taxes~~

~~Income~~accounting for income taxes, ~~are reported in accordance with U.S. GAAP,~~ which requires the establishment of deferred tax accounts for all temporary differences ~~between the~~between: (i) financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax ~~rates.~~rates, and (ii) operating loss and tax credit carryforwards. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law.

~~The~~Realization of deferred ~~income~~ tax assets is contingent on the generation of future taxable income. As a result, management considers whether it is more likely than not that all or ~~liabilities for an oil~~a portion of such assets will be realized during periods when they are available, and gas exploration and development company are dependent on many variables such as estimates of the economic lives of depleting oil and gas reserves and commodity prices. Accordingly, the asset or liability is subject to continuous recalculation and revision of the numerous estimates required, and may change significantly in the event of occurrences such as major acquisitions, divestitures, commodity price changes, changes in reserve estimates, changes in reserve lives, and changes in tax rates or tax laws.

~~The estimated annual effective tax rate of 0% differs from the statutory rate of 21% due primarily to adjustments to the~~if not, management provides a valuation allowance onfor amounts not likely to be recognized.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the ~~deferred tax assets.~~

At December 31, 2019, federal net operating loss carryforwards amounted to approximately $33.9 million, of which approximately $31.6 million expires between 2020 and 2037 which can offset 100% of taxable income and approximately $2.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was $0 at September 30, 2020 and $65,000 at December 31, 2019. In September 2020, the Company received a tax refund of approximately $130,000 associated with the deferred tax asset at December 31, 2019. The Company recorded an allowance on the remaining deferred tax asset at September 30, 2020 and December 31, 2019 primarily due to expected future losses in the near term which would cause cumulative losses being incurred during the 3 year period. There were no recorded unrecognized tax benefits at September 30, 2020 and December 31, 2019.

~~(3) Capital Stock~~

~~Common Stock~~

~~On July 1, 2020, the Company issued 6,511 shares of common stock in the aggregate to the Company’s three directors and CFO and interim CEO.~~

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~On October 2, 2020, the Company issued 4,367 shares of common stock in the aggregate to the Company’s three directors and CFO and interim CEO.~~

~~Rights Agreement~~

Effective March 17, 2017 the Company’s board of directors (the “Board of Directors”) declared a dividend of one right (a “Right”) for each of the Company’s issued and outstanding shares of common stock, $0.001 par value per share (“Common Stock”). The dividend was paid to the stockholders of record at the close of business on March 27, 2017 (the “Record Date”). Each Right entitles the registered holder, subject to the terms of the Rights Agreement dated as of March 16, 2017 (the “Rights Agreement”) between the Company and the Rights Agent, Continental Stock Transfer & Trust Company, to purchase from the Company one one-thousandthestablishment of a ~~share of the Company’s Series~~loss contingency. A ~~Preferred Stock at a price of $1.10 (the “Exercise Price”), subject to certain adjustments.~~

~~The purpose of the Rights Agreement is to reduce the risk that the Company’s ability to use its net operating losses to reduce potential future federal income tax obligations~~loss contingency would be ~~limited~~recognized if the Company’s experiences an “ownership change,” as defined in Section 382 of the Internal Revenue Code. A company generally experiences an ownership change if the percentage of its stock owned by its “5-percent shareholders,” as defined in Section 382 of the Tax Code, increases by more than 50 percentage points over a rolling three-year period. The Rights Agreement is designed to reduce the likelihood that the Company will experience an ownership change under Section 382 of the Tax Code by discouraging any person or group from becoming a 4.95% shareholder and also discouraging any existing 4.95% (or more) shareholder from acquiring additional shares of the Company’s stock.

~~The Rights will not be exercisable until the “Distribution Date”, which is generally defined as the earlier to occur of:(i) a public announcement or filing~~it were probable that a ~~person or group~~liability has ~~become an “Acquiring Person” which is defined~~been incurred as ~~a person or group~~ of ~~affiliated or associated persons or persons acting in concert who, at any time after~~ the date of the ~~Rights Agreement, have acquired, or obtained~~financial statements and the ~~right to acquire, beneficial ownership of 4.95% or more~~amount of the ~~Company’s outstanding shares~~loss can be reasonably estimated. The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of ~~Common Stock;~~each uncertain tax position. The amount that is ultimately incurred for an individual uncertain tax position or ~~a person or group currently owning 4.95% (or more)~~for all uncertain tax positions in the aggregate could differ from the amount recognized. There are 0 unrecorded liabilities for uncertain tax positions related to the Company as of the periods ended March 31, 2021 and September 30, 2020.

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

In June 2016, the Financial Accounting Standards Board issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, which changes accounting requirements for the recognition of credit losses from an incurred or probable impairment methodology to a Current Expected Credit Losses (“CECL”) methodology. The CECL model is applicable to the measurement of credit losses on financial assets measured at amortized cost, including but not limited to trade receivables. The Company adopted this ASU effective October 1, 2020 using a modified retrospective approach. The adoption of this guidance did not have a material effect on the Company’s ~~outstanding shares acquires additional shares~~condensed consolidated financial statements or related disclosures.

The Company is exposed to credit losses primarily through receivables that result from oil and natural gas sales. Estimates of expected credit losses for accounts receivables consider factors such as historical collection experience, credit quality of our customers and current and future economic and market conditions.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

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 ~~Company’s stock; subject to~~financial statements. This ASU removes certain ~~exceptions; or (ii)~~disclosure requirements around transfers between levels of the ~~commencement~~fair value hierarchy and the valuation processes for Level 3 fair value measurements, modifies certain reporting requirements around Level 3 fair value measurements and investments in certain entities that calculate net asset value, and adds certain disclosure requirements for Level 3 fair value measurements. The Company adopted this ASU effective October 1, 2020. The adoption of ~~or announcement of an intention to commence,~~this ASU did not have a ~~tender offer or exchange offer the consummation of which would result in any person becoming an Acquiring Person.~~

~~The Rights, unless extended by the Board of Directors were to expire~~material impact on the ~~earlier~~Company's financial statements.

Issued Accounting Standards Not Yet Adopted

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. This standard did not have any effect on the Company's financial statements as of March ~~16, 2020; or a date~~31, 2021. The Company will continue to evaluate the ~~Board~~effect of Directors determines by resolution in its business judgment that the Rights Agreement is no longer necessary or appropriate; or in certain other specified circumstances. On March 16, 2020 the Board of Directors by unanimous resolution acting without meeting determinedthis standard on future reporting periods through December 31, 2022.

4.Business Combinations

Business Combination Between REP LLC and Tengasco

Immediately prior to ~~extend the expiration date of the Rights Agreement to March 16, 2021 as expressly contemplated by the Rights Agreement.~~

At any time after any person or group of affiliated or associated persons becomes an Acquiring Person, the Board, at its option, may exchange each Right (other than Rights owned by such person or group of affiliated or associated persons which will have become void), in whole or in part, at an exchange ratio of two shares of Common Stock per outstanding Right (subject to adjustment).

~~For further information on the Rights Agreement, please refer to the Rights Agreement that was attached in full as an exhibit to the Company’s Form 8-K filed with SEC on March 17, 2017.~~

On October 20, 2020, the Board of Directors approved the Company entering into that certain Agreement and Plan of Merger (the “Merger Agreement”), dated October 21, 2020, by and among the Company, Antman Sub, LLC, a wholly owned subsidiary of the Company, and Riley Exploration—Permian, LLC. Accordingly, the Rights Agreement and the Rights will automatically terminate at the closing of the Merger ~~contemplated by~~on February 26, 2021, REP LLC converted all of the issued and outstanding Series A Preferred Units into common units of REP LLC. In connection with the Merger, holders of common units of REP LLC were entitled to receive, in exchange for each common unit, shares of common stock of Tengasco (which was renamed Riley Exploration Permian, Inc.), par value $0.001 per share (“Tengasco common stock”) based on the exchange ratio set forth in the Merger Agreement ~~pursuant~~(the “Exchange Ratio”), with cash paid in lieu of the issuance of any fractional shares. The Exchange Ratio was 97.796467 shares of Tengasco common stock for each common unit of REP LLC (as adjusted for the reverse stock split). Immediately prior to the ~~terms~~closing of the ~~Rights Agreement. (See Note (11) Subsequent Events)~~

~~Preferred Stock~~

~~Series A Preferred Stock has~~Merger, Tengasco effected a ~~par value~~one-for-twelve reverse stock split resulting in outstanding common stock of ~~$0.0001 and 10,000~~approximately 17.8 million shares ~~have been designated. No~~including shares of ~~Series A Preferred Stock have been~~Tengasco common stock issued byin the ~~Company pursuant~~Merger. See further discussion in Note 11 – Members'/Shareholders' Equity.

Pursuant to the ~~Rights~~Merger Agreement ~~described above or otherwise.~~and on the Closing Date, each restricted share of common stock issued to holders of restricted common units in REP LLC in the Merger were issued under the 2021 Long Term Incentive Plan (the "2021 LTIP"). See further discussion in Note 13 – Share-Based and Unit-Based Compensation.

~~Table of Contents~~

The combination between REP LLC and Tengasco ~~Inc.~~qualified as a business combination, with REP LLC being treated as the accounting acquirer. The assets acquired and ~~Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~(4) Earnings per Common Share~~

~~We report basic earnings per common share, which exclude~~liabilities assumed were recognized on the effect of potentially dilutive securities, and diluted earnings per common share which include the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliationsconsolidated balance sheet at fair value as of the ~~numerators and denominators~~acquisition date. The fair value measurements of ~~our basic and diluted earnings per share (in thousands except for share and per share amounts~~):

For the Three Months Ended
September 30,

For the Nine Months Ended
September 30,

2020 2019 2020 2019
Income (numerator):
Net loss
$
(813
)

$
(182
)

$
(1,894
)

$
(269
)
Weighted average shares (denominator):
Weighted average shares – basic
10,680,050

10,653,550

10,673,238

10,648,838

Dilution effect of share-based compensation, treasury method
—

—

—

—

Weighted average shares – dilutive
10,680,050

10,653,550

10,673,238

10,648,838

Loss per share:
Basic and fully diluted
$
(0.08
)

$
(0.02
)

$
(0.18
)

$
(0.03
)

~~Options issued to~~ the Company’s directors in which the exercise price was higher than the average market price each quarter were excluded from diluted shares as they would have been anti-dilutive. In addition, the shares that would be issued to employees and Company directors if the thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel have also been excluded from this calculation. (See Note (10) Commitments and Contingencies)

~~(5) Oil and Gas Properties~~

~~The following table sets forth information concerning the Company’s~~ oil and natural gas properties ~~(in thousands)~~:

September 30,
2020

December 31,
2019

Oil and gas properties
$
6,685

$
6,751

Unevaluated properties
—

—

Accumulated depreciation, depletion, and amortization
(2,771
)

(2,366
)
Oil and gas properties, net
$
3,914

$
4,385

~~The Company recorded depletion expense of $405,000~~acquired and $504,000 for the nine months ended September 30, 2020 and 2019, respectively. During the nine months ended September 30, 2019, the Company also recorded in “Accumulated depreciation, depletion, and amortization” a $4,000 gain on asset retirement obligations.

~~(6) Asset Retirement Obligation~~

~~Our~~ asset retirement obligations assumed were derived utilizing an income approach and based, in part, on significant inputs not observable in the market. These inputs represent Level 3 measurements in the ~~estimated present~~fair value hierarchy and include, but are not limited to, estimates of reserves, future commodity prices, future development, future operating costs, future cash flows and the ~~amount we will incur to plug, abandon,~~use of weighted average cost of capital. These inputs required the use of significant judgments and ~~remediate our producing properties~~estimates at the ~~end~~date of ~~their productive lives~~valuation.

The consideration paid in ~~accordance with applicable laws.~~the Merger by REP LLC as the accounting acquirer totaled approximately $26.4 million and was determined based on the closing price of Tengasco’s common stock on February 26, 2021 and the total number of shares outstanding immediately prior to the Merger. The following table summarizes the ~~Company’s Asset Retirement Obligation transactions~~purchase price or consideration for the ~~nine~~Merger (presented in thousands, except per share amounts).


	Consideration
Tengasco common stock price	$	29.64
Tengasco common stock - issued and outstanding as of February 26, 2021	891
Total consideration	$	26,392

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The Company incurred approximately $4.5 million of related costs to date for the Merger, of which $2.2 million and $3.1 million was expensed for the three and six months ended March 31, 2021 as transaction costs on the condensed consolidated statement of operations. Included in the above costs, the Company incurred success fees of $1.75 million upon closing of the Merger which is included within transaction costs on the condensed consolidated statement of operations. The majority of these fees were paid at closing with approximately $0.3 million being paid 30 days after closing.

The Company believes it has completed the determination of the fair value attributable to the assets acquired and liabilities assumed. The following table presents the allocation of the purchase price to the assets acquired and liabilities assumed based on their fair values on February 26, 2021.


	February 26, 2021
Assets
Cash and cash equivalents	$	860
Account receivable	325
Prepaid and other current assets	759
Total current assets	1,944

Oil and gas properties, net	4,525
Other property and equipment, net	91
Right of use assets	42
Other non-current assets	4
Deferred tax assets	2,943
Total non-current assets	7,605

Total assets acquired	$	9,549

Liabilities
Accounts payable	130
Accrued liabilities	409
Current lease liabilities, operating	42
Current lease liabilities, financing	68
Total current liabilities	649

Asset retirement obligations	1,565
Total non-current liabilities	1,565

Total liabilities assumed	2,214

Net identifiable assets acquired	7,335
Goodwill	19,057
Net assets acquired	$	26,392

The goodwill recognized was primarily attributable to a substantial increase in the stock price of Tengasco as of the date the Merger closed, which increased the amount of the consideration transferred. The Company did not integrate the

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

acquisition and the acquisition met the assets held for sale criteria on the Closing Date. See further discussion in Note 15 - Discontinued Operations and Assets Held for Sale.

Post-Acquisition Operating Results

Revenue and net loss attributable to the operations of the assets and liabilities acquired in the Merger of $0 and $115 thousand was included in discontinued operations on the condensed consolidated statement of operations for the three and six months ended March 31, 2021. On April 2, 2021, the Company closed on the sale of the Kansas Reporting Unit with an effective date of March 1, 2021. A net loss of $18.6 million on discontinued operations, net of taxes, was included in the net loss attributable to discontinued operations for the three and six months ended March 31, 2021.

Pro Forma Operating Results

The following pro forma combined results for the three and six months ended March 31, 2021 and 2020 reflect the consolidated results of operations of the Company as if the Merger had occurred on October 1, 2019. The pro forma information includes adjustments for $3.2 million of transaction costs being reclassified to the first quarter of fiscal year 2020 instead of $2.2 million and $1.0 million of transaction costs recorded in the three months ended March 31, 2021 and December 31, 2020. Additionally, the Company adjusted for $0.9 million of oil and natural gas property impairment Tengasco recognized under the full-cost method of accounting, which would not have been recognized under the successful efforts method, during the three months ended December 31, 2020. Also, the pro forma information has been effected for taxes with a 21% tax rate. The common stock was also adjusted for the conversion of the REP LLC preferred units into common units and retroactively adjusted for the Exchange Ratio and 1-for-12 reverse stock split.


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)
Total Revenues	$	37,259	$	25,406	$	60,273	$	54,955
Pro Forma Net Income (Loss) from Continuing Operations	(16,877)		75,053		(23,364)		64,999
Pro Forma Net Income (Loss) from Discontinued Operations	(25)		19		25		(18,133)
Pro Forma Net Income (Loss) before Taxes	(16,902)		75,072		(23,339)		46,866
Pro forma income tax benefit (expense)	3,549		(15,765)		4,901		(9,842)
Pro Forma Net Income (Loss)	$	(13,353)	$	59,307	$	(18,438)	$	37,024

Net Income (Loss) per Share/Unit from Continuing Operations:
Basic	$	(0.96)	$	4.34	$	(1.33)	$	3.77
Diluted	$	(0.96)	$	4.32	$	(1.33)	$	3.76

Net Income (Loss) per Share/Unit from Discontinued Operations:
Basic	$	0	$	0	$	0	$	(1.05)
Diluted	$	0	$	0	$	0	$	(1.05)

The pro forma combined financial information is for informational purposes only and is not intended to represent or to be indicative of the combined results of operations that the Company would have reported had the Merger been completed as of October 1, 2019 and should not be taken as indicative of the Company's future combined results of operations. The actual results may differ significantly from that reflected in the pro forma combined financial information for a number of reasons, including, but not limited to, differences in assumptions used to prepare the pro forma combined financial information and actual results.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

5. Oil and Natural Gas Properties

Oil and natural gas properties are summarized below:


	March 31, 2021		September 30, 2020

	($ in thousands)
Proved	$	359,407	$	326,420
Unproved	25,570		32,084
Work-in-progress	10,021		15,398
	394,998		373,902
Accumulated depletion and amortization	(75,182)		(63,176)
Total oil and natural gas properties, net	$	319,816	$	310,726

Depletion and amortization expense for proved oil and natural gas properties was $6.1 million and $5.2 million, respectively, for the three months ended March 31, 2021 and 2020. Depletion and amortization expense for proved oil and natural gas properties was $12.0 million and $10.7 million, respectively, for the six months ended March 31, 2021 and 2020.

The Company incurred $5.5 million and $1.7 million of exploration costs for the three months ended March 31, 2021 and 2020, respectively, $5.4 million and $0 of which related to the expiration of oil and natural gas leases. The Company also incurred $0.1 million and $1.7 million of geological and geophysical costs during the three months ended March 31, 2021 and 2020, respectively. The Company incurred $5.9 million and $2.5 million of exploration costs for the six months ended March 31, 2021 and 2020, respectively, $5.8 million and $0.5 million of which related to the abandonment of oil and natural gas leases. The Company also incurred $0.1 million and $1.9 million of geological and geophysical costs during the six months ended March 31, 2021 and 2020, respectively.

Acquisitions and Divestitures of Oil and Natural Gas Properties

Through the Merger on February 26, 2021, the Company acquired approximately 11,000 net acres (unaudited) located in central Kansas. The acquisition included the Kansas Properties which included 153 producing oil wells, 19 shut-in wells, 6 temporarily abandoned wells, and 36 active disposal wells. The Company also acquired all onsite production management and field personnel as a result of the Merger. See further discussion in Note 4 - Business Combinations and Note 15 - Discontinued Operations and Assets Held for Sale.

On March 10, 2021, the Company entered into a PSA to sell the Kansas Properties for an agreed upon purchase price of $3.5 million (subject to certain adjustments), contingent upon certain conditions to closing. The effective date of the sale was March 1, 2021 and the sale closed on April 2, 2021 for the agreed upon purchase price, adjusted for closing costs. As of March 31, 2021, the assets and liabilities associated with these divested assets were classified as held for sale in the accompanying condensed consolidated balance sheet. See further discussion in Note 15 - Discontinued Operations and Assets Held for Sale.

On December 20, 2019, the Company acquired 1,237 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 a PSA 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, capitalized asset retirement cost and ARO.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

6.Other Non-Current Assets

Other non-current assets consisted of the following:


	March 31, 2021		September 30, 2020

	($ in thousands)
Debt issuance costs, net	$	1,680	$	1,867
Prepayments to outside operators	184		284
Right of use assets	507		700
Other deposits	71		98

Total other non-current assets, net	$	2,442	$	2,949

7.Derivative Instruments

Crude Oil and Natural Gas Contracts

The Company uses commodity based derivative contracts to reduce exposure to fluctuations in crude oil and natural gas prices. While the use of these contracts limits the downside risk for adverse price changes, their use may also limit future revenues from favorable price changes. For the three and six months ended March 31, 2021 and 2020, 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.

As of March 31, 2021, the Company's oil and natural gas 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.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table summarizes the open financial derivative positions as of March 31, 2021, related to crude oil and natural gas production.


		Weighted Average Price
Calendar Quarter	Notional Volume	Fixed		Put		Call
		($ per unit)
Crude Oil Swaps (Bbl)
Q2 2021	527,768	$	51.38	$	—	$	—
Q3 2021	564,278	$	51.57	$	—	$	—
Q4 2021	558,116	$	51.65	$	—	$	—
2022	960,000	$	51.05	$	—	$	—
2023	30,000	$	52.11	$	—	$	—

Natural Gas Swaps (Mcf)
Q2 2021	450,000	$	2.97	$	—	$	—
Q3 2021	450,000	$	2.97	$	—	$	—
Q4 2021	450,000	$	2.97	$	—	$	—

Crude Oil Collars (Bbl)
2022	360,000	$	—	$	35.00	$	42.63

Crude Oil Basis (Bbl)
Q2 2021	435,000	$	0.40	$	—	$	—
Q3 2021	435,000	$	0.40	$	—	$	—
Q4 2021	435,000	$	0.40	$	—	$	—
2022	240,000	$	0.70	$	—	$	—

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 Company's revolving credit facility.

The notional amount of the interest rate swaps, as of March 31, 2021 and September 30, 2020, (was $95 million in ~~thousands)~~:

Balance December 31, 2019
$
1,998

Accretion expense
94

Liabilities incurred
—

Liabilities settled
—

Liabilities relieved - sold properties
(63
)
Balance September 30, 2020
$
2,029

total with $55 million expiring on September 28, 2021 and an additional $40 million effective from September 29, 2021 through October 28, 2023.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

~~Table of Contents~~(Unaudited)

Balance Sheet Presentation of Derivatives

~~Tengasco, Inc.~~The following table presents the location and ~~Subsidiaries~~fair value of the Company’s derivative contracts included in the accompanying consolidated balance sheets as of March 31, 2021 and September 30, 2020.

~~Notes to Unaudited Condensed Consolidated Financial Statements~~


	March 31, 2021
Balance Sheet Classification	Gross Fair Value		Amounts Netted		Net Fair Value
	($ in thousands)
Current derivative assets	$	764	$	(412)	$	352
Non-current derivative assets	698		(134)		564
Current derivative liabilities	(14,722)		412		(14,310)
Non-current derivative liabilities	(6,210)		134		(6,076)
Total	$	(19,470)	$	—	$	(19,470)

	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		0
Non-current derivative liabilities	(1,549)		1,549		0
Total	$	21,921	$	—	$	21,921

The following table presents the Company's derivative activities for the three and six months ended March 31, 2021 and 2020:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)
Fair value of net asset (liability), beginning of period	$	2,839	$	(3,632)	$	21,921	$	14,959
Gain (loss) on derivatives	(24,903)		69,239		(38,812)		51,204
Settlements on derivatives	2,594		(4,936)		(2,579)		(5,492)
Fair value of net asset (liability), end of period	$	(19,470)	$	60,671	$	(19,470)	$	60,671

The Company recognized settlements and changes in the fair value of its derivative contracts as a single component of other income (expenses). The following table disaggregates the Company's gain (loss) on derivatives presented in the condensed consolidated statement of operations for the three and six months ended March 31, 2021 and 2020:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)
Settlements on derivatives	$	(2,594)	$	4,936	$	2,579	$	5,492
Unrealized gain (loss) on derivatives	(22,309)		64,303		(41,391)		45,712
Gain (loss) on derivatives	$	(24,903)	$	69,239	$	(38,812)	$	51,204

RILEY EXPLORATION PERMIAN, INC.

~~(7) Long-Term Debt~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

8.Fair Value Measurements

The carrying values of financial instruments comprising cash and ~~Lease~~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.

Assets and Liabilities Measured on a Recurring Basis

~~Long Term Debt~~

AtThe following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2021 and September 30, 2020, by level within the ~~Company had~~fair value hierarchy:


	March 31, 2021
	Level 1		Level 2		Level 3		Total
	($ in thousands)
Financial assets:
Commodity derivative assets	$	0	$	916	$	0	$	916
Financial liabilities:
Commodity derivative liabilities	$	0	$	(20,084)	$	0	$	(20,084)
Interest rate liabilities	$	0	$	(302)	$	0	$	(302)

	September 30, 2020
	Level 1		Level 2		Level 3		Total
	($ in thousands)
Financial assets:
Commodity derivative assets	$	0	$	24,341	$	0	$	24,341
Financial liabilities:
Commodity derivative liabilities	$	0	$	(1,672)	$	0	$	(1,672)
Interest rate liabilities	$	0	$	(748)	$	0	$	(748)

Assets and Liabilities Measured at Fair Value on a ~~revolving credit facility~~Non-Recurring Basis

Assets and liabilities accounted for at fair value on a non-recurring basis in accordance with ~~Prosperity Bank. This has historically been~~the fair value hierarchy include the initial recognition of asset retirement obligations, the fair value of oil and natural gas properties, and goodwill 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 NYMEX forward curve pricing, adjusted for estimated location and quality differentials, as well as other factors that the Company’s ~~primary source to fund working capital~~management believes will impact realizable prices. These inputs require significant judgments and ~~capital spending. Under~~estimates by the ~~credit facility, loans~~Company’s management at the time of the valuation.

The fair value of asset retirement obligations incurred and ~~letters~~acquired during the six months ended March 31, 2021 and 2020, totaled approximately $53 thousand and $889 thousand, respectively. The fair value of ~~credit are available~~additions to the ~~Company on~~asset retirement obligation liabilities is measured using valuation techniques consistent with the income approach, which converts future cash flows to a ~~revolving basis in an~~single discounted amount. Significant inputs to the valuation include: (i) $50 thousand estimated plug and abandonment cost per well for all oil and natural gas wells and $52 thousand for estimated plug and abandonment cost per well for all disposal wells for the six months ended March 31, 2021 and 2020; (ii) a 27 year and 12 year weighted average by fair value of the estimated remaining life per well for the six months ended March 31, 2021 and 2020; (iii) future inflation factors; and (iv) our average credit-adjusted risk-free rate of 5.17% and 8.34% for the six months ended March 31, 2021 and 2020. These assumptions represent Level 3 inputs.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

If the carrying amount ~~outstanding not~~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 ~~exceed~~fair value. The fair value of our oil and natural gas properties is determined using valuation techniques consistent with the ~~lesser of $50 million or the Company’s borrowing base in effect from time~~income and market approach. The factors used to ~~time. As of September 30, 2020, the Company’s borrowing base was $3.1 million,~~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.

9.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 was previously owned by Oakspring Energy Holdings, LLC ("Oakspring") and by a wholly-owned subsidiary of Riley Exploration Group, Inc. ("REG"). On December 31, 2020, Oakspring contributed its interest in Combo to certain investment funds of Yorktown Partners, LLC, and the wholly-owned subsidiary of REG contributed its' interest in Combo to Riley Exploration Group, LLC.

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 following table presents revenues from contract services for related parties:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)
Combo	$	300	$	750	$	600	$	1,500
REG	300		300		600		600
Contract services - related parties	$	600	$	1,050	$	1,200	$	2,100

Cost of contract services	$	91	$	138	$	239	$	306

10.Revolving Credit Facility

On September 28, 2017, REP LLC and SunTrust Bank, now Truist Bank as successor by merger, as administrative agent, entered into a credit limit based on current covenants of $1.442 million. While the credit limit has not yet been formally reduced, the Company has experienced total negative EBITDA for the trailing 4 quarters ended September 30, 2020, which would result inagreement to establish a ~~zero credit limit if the formal borrowing base review would have occurred at September 30, 2020, therefore prohibiting any borrowings on the Company’s~~senior secured revolving credit facility. The credit facility had an initial borrowing base of $25 million with a maximum facility amount of $500 million.

On October 21, 2020, REP LLC entered into the Seventh Amendment and Consent to its credit facility to incorporate the changes in the legal structure of REP LLC upon consummation of the Merger, including the joinder of the Company as the parent guarantor thereto. The Seventh Amendment was effective upon closing of the Merger. Effective March 5, 2021, the Company and REP LLC entered into the Eighth Amendment to the credit facility pursuant to which the parties thereto reaffirmed the borrowing base at $135 million with total commitments increasing to $135 million and extended the maturity date of the facility by an additional two years.

The credit facility maturity date is ~~secured by substantially~~set to occur on September 28, 2023 in accordance with the Eighth Amendment. Substantially all of the Company’s ~~producing~~assets are pledged to secure the credit facility.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table summarizes the Company's interest expense:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)				($ in thousands)
Interest expense	$	962	$	1,179	$	2,002	$	2,319
Amortization of debt issuance costs	160		165		316		318
Unused commitment fees	43		74		82		147
Total interest expense	$	1,165	$	1,418	$	2,400	$	2,784

The weighted average interest rate as of March 31, 2021 and ~~non-producing oil and gas properties. The credit facility includes certain covenants with which the Company is required to comply. At~~ September 30, 2020 ~~these covenants include the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x;~~was 3.19% and ~~(c) Interest Coverage > 3.0x. At~~4.09%, respectively.

As of March 31, 2021 and September 30, 2020, the ~~interest rate on this credit facility was 3.75%. The~~ Company was in compliance with all covenants contained in the credit agreement and had $97.5 million and $101 million, respectively, of outstanding borrowings and an additional $37.5 million and $34 million, respectively, available under the borrowing base.

11.Members’/Shareholders' Equity

On March 1, 2021, the Company granted 3,374 restricted shares, which vest over a 1-year period, under the 2021 LTIP to the newly-added, independent directors that joined the Board of Directors in conjunction with the Merger. See further discussion in Note 13 – Share-Based and Unit-Based Compensation.

Pursuant to the Merger Agreement and on February 26, 2021, the Company granted 198,024 restricted shares to certain executives under the 2021 LTIP. See further discussion in Note 13 – Share-Based and Unit-Based Compensation.

On October 1, 2020, REP LLC granted 13,309 restricted units to certain employees and executives which vest over a three-year period, which reduced the 2018 LTIP common units available for issuances to 135,241. See further discussion in Note 13 – Share-Based and Unit-Based Compensation.

On February 4, 2021, the Board of Managers of REP LLC declared a $3.8 million cash dividend, paid on February 5, 2021. The cash dividend was declared for all issued and outstanding common units, including vested and unvested under the Riley Exploration - Permian, LLC 2018 Long Term Incentive Plan (the "2018 LTIP") of REP LLC. 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. See further discussion for the Company's restricted units in Note 13 – Share-Based and Unit-Based Compensation.

On March 4, 2021, the Board of Directors of the Company declared a $5 million cash dividend ($0.28 per share) payable on all issued and outstanding common shares of the Company as of April 16, 2021, and was paid on May 7, 2021. The portion of the cash dividend attributable to the unvested restricted common shares was accrued and will be paid once the unvested restricted units fully vest. Cash dividends are approved at the sole discretion of the Board of Directors. See further discussion for the Company's restricted shares in Note 13 – Share-Based and Unit-Based Compensation.

On March 15, 2021, the Company granted restricted shares and stock awards to certain employees and executives under the 2021 LTIP effective April 1, 2021. See further discussion in Note 13 – Share-Based and Unit-Based Compensation.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

12.Preferred Units

As of August 13, 2020, REP LLC entered into the Fourth Amended and Restated Limited Liability Company Agreement (the "Fourth LLC Agreement") which declared the mandatory redemption date for all 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 was set to mature on September 28, 2023.

Immediately prior to the closing of the Merger on February 26, 2021 and in accordance with the Merger Agreement, REP LLC converted each issued and outstanding Series A Preferred Unit into one common units and paid the holders of REP LLC Series A Preferred Units a cash payment equal to the amount of any unpaid dividends accruing between October 1, 2020 and February 26, 2021 in accordance with its Fourth LLC Agreement. The Company converted 511,695 Series A Preferred Units with a value of $61.2 million to common units in accordance with the Fourth LLC Agreement and Merger Agreement. Additionally, the cash payment of any unpaid dividends accrued between October 1, 2020 and February 26, 2021 was $1.5 million on 511,695 Series A Preferred Units.

The tables below summarize the changes in preferred units during the ~~quarter~~three and six months ended March 31, 2021 and 2020:


	Units	Amount
		($ in thousands)
Balance, September 30, 2020	504,168	$	60,292
Dividends paid in kind	7,527	904
Balance, December 31, 2020	511,695	61,196
Units converted to common units	(511,695)	(61,196)
Balance, March 31, 2021	0	$	0


	Units	Amount
		($ in thousands)

Balance, September 30, 2019	475,152	$	56,810
Dividends paid in kind	7,094	851
Balance, December 31, 2019	482,246	57,661
Dividends paid in kind	7,199	864
Balance, March 31, 2020	489,445	$	58,525

After the closing of the Merger, the Company's authorized capital stock includes 25 million shares of preferred stock with a par value of $0.0001 per share, of which 0 shares were issued and outstanding as of March 31, 2021.

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 was not considered to have sole control over the contractually mandated redemption during the year ended September 30, ~~2020.~~ 2020 since the Series A Preferred Units were set for redemption in 2024 prior to the conversion of the Series A Preferred Units into common units and exchange of common units for common stock in the merger, the Series A Preferred Units were classified as mezzanine equity prior to their conversion for the period in which they were outstanding.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

13.Share-Based and Unit-Based Compensation

In connection with the Merger, the Company shareholders adopted an omnibus equity incentive plan, the 2021 LTIP, for the employees, consultants and the directors of the Company and its affiliates who perform services for the Company. The holders of unvested restricted units issued under the 2018 LTIP were issued substitute awards under the 2021 LTIP at the closing of the Merger. Upon the closing of the Merger and after giving effect to the adjustment resulting from the 1-for-12 reverse stock split, the 2021 LTIP had 1,387,022 shares of common stock available for issuance, of which 1,185,624 shares remained available as of March 31, 2021.

2021 Long-Term Incentive Plan

The 2021 LTIP will provide for potential grants of: (i) incentive stock options qualified as such under U.S. federal income tax laws ("ISO's:); (ii) stock options that do not qualify as incentive stock options; (iii) stock appreciation rights, or SARs; (iv) restricted stock awards; (v) restricted stock units, or RSUs; (vi) stock awards; (vii) performance awards; (viii) dividend equivalents; (ix) other stock-based awards; (x) cash awards; and (xi) substitute awards, all of which will be collectively be referred to as the "Awards".

The 2021 LTIP authorizes the Compensation Committee to administer the plan and designate eligible persons as participants, determine the type or types of Awards to be granted to an eligible person, determine he number of shares of stock or amount of cash to be covered by the Awards, approve the forms of award agreements for use under the plan, determine the terms and conditions of any Award, modify, waive or adjust any term or condition of an Award that has been granted, among other responsibilities delegated by the Company's Board.

Restricted Units: The Company ~~had no outstanding borrowing~~granted 198,024 restricted shares to certain executives under the ~~facility as of September 30, 2020 or December 31, 2019. However, if~~2021 LTIP in connection with the ~~Company had borrowings~~Merger. These grants substituted restricted common shares issued under the ~~credit facility at September 30, 2020, the Company would not have been in compliance with EBITDA related covenants as the Company reported negative EBITDA~~2021 LTIP for the ~~trailing four quarters ended September 30, 2020.~~

~~During~~unvested restricted units granted under the ~~second quarter~~2018 LTIP. These restricted shares vest over a period of ~~2020,~~8- to 33-months and the ~~Company was approved by~~holder receives dividends, in arrears, once the Small Business Administration to receive a Paycheck Protection Program (“PPP”) loan in the amount of approximately $166,000. This loan was funded by Prosperity Bank in May 2020. The PPP loan is not part of the credit facility with Prosperity Bank as described above and therefore is not subject to the same terms as Company’s credit facility. The PPP loan has an interest rate of 1% with a maturity date of May 2022. There are no payments due during the first six months of the loan. After the six-month period has expired, all outstanding accrued interest is due. At that time, the remaining unforgiven portion of the loan will be due in 18 equal monthly installments of principal and interest.shares vest. The Company ~~applied~~has accrued for forgiveness of the amount due on the PPP loan based on spending the loan proceeds on eligible expenses as defined by statute. On November 5, 2020, Prosperity Bank notified the Company that the PPP loan had been forgiventhese dividends which are reported in accrued liabilities and ~~the loan was closed. During the fourth quarter of 2020, the Company will record~~ other ~~income of $166,000 as a result of the PPP loan forgiveness.~~

~~Lease Liabilities~~

~~Effective January 1, 2019, the Company adopted ASU 2016-02~~ ~~Leases (Topic 842).~~ ~~We first determine if a contract~~non-current liabilities. The total expense is a lease at inception of the arrangement. To the extent that we determine an arrangement represents a lease, we then classify that lease as an operating lease or a finance lease. As of January 1, 2019, the Company capitalizes its operating leases on the Consolidated Balance Sheet as a right of use asset and a corresponding lease liability. The Company also capitalizes its finance leases on the Consolidated Balance Sheet as other property and equipment and a corresponding lease liability. The right of use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Lease expense for operating lease payments is recognizedamortized on a straight-line basis, over the ~~lease term. Short term leases that have an initial term~~vesting period. The Company recorded $403 thousand and $0 of ~~one year or less are not capitalized unless~~share-based compensation expense for the three and six months ended March 31, 2021 and 2020 related to this issuance. Approximately $5.5 million of additional share-based compensation expense will be recognized with this grant over the next 32 months.

On March 1, 2021, the Company ~~intends~~granted 3,374 restricted shares to ~~renew~~certain directors under the ~~lease~~2021 LTIP, which vest over a 1-year period. The holder receives dividends, in arrears, once the shares vest. The Company has accrued for these dividends which are reported in accrued liabilities and other non-current liabilities. The total expense is amortized on a straight-line basis, over the vesting period. The Company recorded $6 thousand and $0 of share-based compensation expense for the three and six months ended March 31, 2021 and 2020 related to ~~extend~~this issuance. Approximately $75 thousand of additional share-based compensation expense will be recognized with this grant over the ~~initial term past one year.~~next 11 months.

~~We lease certain office space,~~On March 15, 2021, the Company granted restricted shares and stock awards with a ~~storage yard, and field vehicles~~fixed dollar amount of $4.6 million that will be settled in a variable number of shares, based on the 10-day weighted average share price prior to ~~support our operations. A more detailed description~~April 1, 2021. $3.7 million of the ~~Company’s lease types~~award was fully vested on April 1, 2021. The remaining $0.9 million will vest on April 1, 2022. As the number of shares was variable on the grant date, the Company accounted for the awards as a liability which was valued on March 31, 2021. The Company recorded $4.2 million of share-based compensation expense for the three and six months ended March 31, 2021 related to this issuance with the liability recorded in accrued liabilities on the balance sheet as of March 31, 2021. Approximately $0.9 million of additional share-based compensation expense will be recognized with this grant over the next 12 months.

Total share-based compensation expense of $4.6 million and $0, respectively, is included ~~below.~~in general and administrative costs on the Company's condensed consolidated statement of operations for all of the issuances outstanding for the three and six months ended March 31, 2021 and 2020. The Company will recognize any forfeited shares, and any unpaid dividends for those shares, as they occur as an increase to accrued liabilities and a reduction from shareholders' equity on the consolidated balance sheet.

RILEY EXPLORATION PERMIAN, INC.

~~Office~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

2018 Long-Term Incentive Plan

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 ~~Storage Yard~~

the holder receives dividends, in arrears, once the units vest. The Company has accrued for these dividends and are reported in accrued liabilities and other non-current liabilities. The total expense is amortized on a straight-line basis, over the vesting period. The Company recorded $112 thousand and $165 thousand of unit-based compensation expense for the three months ended March 31, 2021 and 2020 related to this issuance. The Company recorded $278 thousand and $318 thousand of unit-based compensation expense for the six months ended March 31, 2021 and 2020 related to this issuance.

The Company ~~maintains an office~~granted 15,767 restricted units to ~~support its corporate operations. This office agreement~~certain executives effective February 1, 2020 which vest over a three-year period and the Company simultaneously repurchased 1,229 shares from these executives for payment of their employee tax withholding obligations, resulting in a net issuance of 14,538. The total expense is ~~with~~amortized on a ~~third party and was structured with a 39 month initial term and an August 31, 2020 expiration date.~~straight-line basis, over the vesting period. The Company ~~renewed~~recorded $81 thousand and $41 thousand of unit-based compensation expense for the ~~lease for 12 additional~~three months ~~thereby extending the expiration date~~ended March 31, 2021 and 2020 related to ~~August 31, 2021. The Company’s corporate office lease is classified as an operating lease.~~

this issuance. The Company ~~maintains an office~~recorded $203 thousand and $41 thousand of unit-based compensation expense for the six months ended March 31, 2021 and 2020 related to ~~support its field operations. This office~~this issuance.

On October 1, 2020, the Company granted 13,309 restricted units to certain executives which vest over a three-year period. The total expense is ~~with a third party and is~~amortized on a ~~month-to-month lease. However,~~straight-line basis, over the vesting period. The Company recorded $83 thousand and $0 of unit-based compensation expense for the three months ended March 31, 2021 and 2020 related to this issuance. The Company recorded $208 thousand and $0 of unit-based compensation expense for the six months ended March 31, 2021 and 2020 related to this issuance.

On October 5, 2020, an executive of the Company ~~intends to continue to renew this lease~~forfeited 904 restricted units from the grant dated April 29, 2019 and 1,802 restricted units from the grant dated February 1, 2020 totaling a total forfeiture of 2,706 restricted units.

Total unit-based compensation expense of $276 thousand and $206 thousand, respectively, is for all of the issuances outstanding for the ~~foreseeable future. Based~~three months ended March 31, 2021 and 2020. Total unit-based compensation expense of $689 thousand and $359 thousand, respectively, is for all of the issuances outstanding for the six months ended March 31, 2021 and 2020. Unit-based compensation expense is included in general and administrative costs on the ~~Company’s intent to renew the lease, the Company is assuming the same lease term as its corporate office lease for calculation~~Company's condensed consolidated statement of ~~its right of use asset and lease liability. The Company’s field office lease is classified as an operating lease.~~

operations. The Company ~~maintains~~will recognize any forfeited units, and any unpaid dividends for those units, as they occur as a ~~yard~~reduction to ~~store certain equipment used in its field operations. This storage yard agreement is with a third party~~accrued liabilities and ~~is on a month-to-month lease. However, the Company intends to continue to renew this lease for the foreseeable future. Based~~members' equity on the ~~Company’s intent to renew the lease, the Company is assuming the same lease term~~consolidated balance sheet.

14.Income Taxes

REP LLC became a taxable entity as ~~its corporate office lease for calculation of its right of use asset and lease liability. The Company’s storage yard is classified as an operating lease.~~

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

As a result of its Merger with Tengasco on February 26, 2021. See further discussion in Note 4 - Business Combinations. While REP LLC was organized as a limited liability company, taxable income passed through to its unit holders. Accordingly, a provision for federal and state corporate income taxes has been made only for the ~~renewal~~operations of REP LLC from February 27, 2021 through March 31, 2021 in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the Merger into a corporation on February 26, 2021, the Company established a $13.6 million provision for deferred income taxes. The majority of this deferred tax liability was related to a change in tax status as reflected in the rate reconciliation table below.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The components of the Company's consolidated provision for income taxes from continuing operations are as follows:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)				($ in thousands)

Current income tax expense:
Federal	$	780	$	0	$	780	$	0
State	363		0		(2)		0
Total current income tax expense	1,143		0		778		0
Deferred income tax expense:
Federal	14,006		0		14,006		0
State	(918)		0		(1,068)		0
Total deferred income tax expense	13,088		0		12,938		0
Total income tax expense	$	14,231	$	0	$	13,716	$	0

A reconciliation of the statutory federal income tax rate to the Company's effective income tax rate is as follows:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)				($ in thousands)

Tax at statutory rate	21.0	%	21.0	%	21.0	%	21.0	%
Nondeductible compensation	(0.3)	%	0	%	(0.2)	%	0	%
Transaction costs	(0.4)	%	0	%	(0.3)	%	0	%

State income taxes, net of federal benefit	(2.5)	%	0	%	0.1	%	0	%
Change in Tax Status	(71.6)	%	0	%	(49.6)	%	0	%
Income Subject to Taxation by REP LLC's Unitholders	(20.9)	%	(21.0)	%	(20.9)	%	(21.0)	%
Effective income tax rate	(74.7)	%	0	%	(49.9)	%	0	%

The Company's federal income tax returns for the years subsequent to September 30, 2017 remain subject to examination. The Company's income tax returns in major state income tax jurisdictions remain subject to examination for various periods subsequent to September 30, 2017. The Company currently believes that all other significant filing positions are highly certain and that all of its other significant income tax positions and deductions would be sustained under audit or the final resolution would not have a material effect on the consolidated financial statements. Therefore, the Company has not established any significant reserves for uncertain tax positions.

15.Discontinued Operations and Assets Held For Sale

Kansas Reporting Unit

On March 10, 2021, the Company entered into a PSA to divest of the Kansas Reporting Unit for an agreed upon purchase price of $3.5 million before certain closing adjustments. In addition, the Company also agreed to assign to the buyer its lease associated with Tengasco's former corporate office ~~lease,~~in Greenwood Village, Colorado. With Tengasco qualifying as a business and the Kansas Reporting Unit making up a significant portion of the assets of Tengasco, the Company ~~recorded right-of-use~~concluded that the transaction met the requirements of assets held for sale and discontinued operations upon the acquisition date. The effective date of the sale was March 1, 2021 and the sale closed on April 2, 2021 for the agreed upon purchase price, plus approximately $0.2 million in net closing adjustments.

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

The following table presents the amounts reported in the condensed consolidated statement of operations as discontinued operations:


Three Months Ended March 31, 2021	Tengasco
	($ in thousands)
Oil and natural gas sales	$	0
Total revenues	0
Lease operating expenses	115
Goodwill impairment	18,516
Total expenses	18,631
Loss from discontinued operations before income taxes	(18,631)
Income tax benefit	25
Net loss from discontinued operations, net of tax	$	(18,606)

For further discussion of revenues and expenses included in discontinued operations, see further discussion in Note 4 - Business Combinations.

The following table presents the carrying amount of assets and liabilities associated with ~~operating leases~~discontinued operations reported on the condensed consolidated balance sheets as of ~~approximately $63,000.~~March 31, 2021:


	Tengasco
Assets	($ in thousands)
Accounts receivable	$	2
Prepaid expenses and other current assets	101
Total Current Assets Associated with Discontinued Operations	103

Oil and natural gas properties, net (successful efforts)	4,526
Goodwill	540
Total Non-Current Assets Associated with Discontinued Operations	5,066

Total Assets Associated with Discontinued Operations	$	5,169

Liabilities
Accounts Payable	$	63
Accrued liabilities	32
Total Current Liabilities Associated with Discontinued Operations	95

Asset retirement obligations	1,607
Total Non-Current Liabilities Associated with Discontinued Operations	1,607

Total Liabilities Associated with Discontinued Operations	$	1,702

~~Field Vehicles~~

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

16.Net Income (Loss) Per Share/Unit

Net income (loss) per share/unit is calculated using a retroactive application of the Exchange Ratio and the 1-for-12 reverse stock split. Certain restricted shares of the Company met the criteria of a participating security. The Company ~~leases certain vehicles from a third party for use in its field operations.~~ calculated net income or loss per share/unit using the two-class method.

The ~~lease term for each vehicle is based on expected daily use~~table below sets forth the computation of ~~the vehicles by the field personnel, typically between 18~~basic and 36 months. The Company also pays an upfront fee at the commencement of the lease term. The Company can continue to lease the vehicles past the initial lease term on a month-to-month basis. In addition, each vehicle has a residual value guarantee at the end of the lease term. The Company’s field vehicle leases are classified as finance leases.

~~Significant Judgment~~

To determine whether the Company’s contracts contain a lease component, the Company is required to exercise significant judgment. The Company will review each contract to determine if: an asset is specified in the contract; the asset is physically distinct; the supplier does not have substantive substitution rights; the Company obtains substantially all economic benefit from use of the asset; and the Company can direct the use of the asset. The Company also determines the appropriate discount rate to use on each lease. If there is a stated rate in the contract, the Company will use the stated rate as its discount rate. The contract associated with the field vehicles includes a stated rate typically between 5% and 6.5%. These stated rates for the field vehicle agreements were used as the discount rates. If there is no stated rate, the Company will use its borrowing rate as the discount rate. The contracts associated with the offices and yard do not include a stated rate. The Company used its borrowing rate of 3.75% as the discount rate for these agreements.

~~Components of lease costs~~diluted net income (loss) per unit for the three ~~months~~ and ~~nine~~six months ~~ended September 30, 2020 and 2019 (in thousands~~):

Period Ended
For the Three Months Ended For the Nine Months Ended

Statement of Operations Account
September 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019

Operating lease cost:

Production costs and taxes

$
3

$
3

$
10

$
10

General and administrative

13

12

37

37

Total operating lease cost

$
16

$
15

$
47

$
47

Finance lease cost:

Amortization of right of use assets
Depreciation, depletion, and amortization

$
20

$
21

$
56

$
62

Interest on lease liabilities
Net interest expense

1

1

4

4

Total finance lease cost
$
21

$
22

$
60

$
66

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~Supplemental lease related cash flow information for the three months and nine months ended September 30, 2020 and 2019 (in thousands~~):

Period Ended
For the Three Months Ended For the Nine Months Ended
September 30, 2020 September 30, 2019 September 30, 2020 September 30, 2019

Cash paid for amounts included in lease liabilities:
Operating cash flows from operating leases
$
16

$
15

$
47

$
45

Operating cash flows from finance leases
1

1

4

4

Finance cash flows from finance leases
15

9

34

40

Right of use assets obtained in exchange for lease obligations:
Operating leases
—

—

63

98

~~Supplemental lease related balance sheet information as of September 30, 2020 and December 31, 2019 (in thousands~~):

Balance Sheet as of
September 30, 2020 December 31, 2019

Operating Leases:

Right of use asset - operating leases
$
58

$
41

Lease liabilities - current
$
58

$
41

Lease liabilities - noncurrent
—

—

Total operating lease liabilities
$
58

$
41

Finance Leases:

Other property and equipment, gross
$
293

$
295

Accumulated depreciation
(159
)

(146
)
Other property and equipment, net
$
134

$
149

Lease liabilities - current
$
58

$
61

Lease liabilities - noncurrent
42

41

Total finance lease liabilities
$
100

$
102

~~Weighted average remaining lease term and discount rate as of September 30, 2020:~~

Operating Leases Finance Leases

Weighted average remaining lease term 0.9 years 1.1 years
Weighted average discount rate 3.75 % 5.35 %

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~Maturity of lease liabilities as of September 30, 2020 (in thousands~~):

Operating Leases Finance Leases

2020
$
16

$
21

2021
43

67

2022
—

15

Total lease payments
59

103

Less imputed interest
(1
)

(3
)
Total
$
58

$
100

~~(8) Liquidity~~

Through November 2021, the Company believes its revenues as well as cash on hand will be sufficient to fund operating costs and general and administrative expenses. In addition, although the Company has recently experienced net loss and negative cash flow, the Company’s current assets exceed its current liabilities and are expected to continue through November 2021. If revenues and cash on hand are not sufficient to fund these expenses and the Company needed to borrow funds against the credit facility, the Company would require a waiver on the EBITDA related covenants, or a change in the covenants, in order for the borrowing to occur.

~~(9) Fair Value Measurements~~

FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows:

~~Level 1 – Observable inputs, such as unadjusted quoted prices in active markets, for substantially identical assets and liabilities.~~

Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices for similar assets and liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a specified or contractual term, the input must be observable for substantially the full term of the asset or liability.

Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by management. The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of observable inputs and minimize the use of unobservable inputs.

The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Further, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

~~Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions.~~

Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment. The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long-term debt in our balance sheet approximates fair value as of September 30, 2020 and December 31, 2019.

~~Table of Contents~~

~~Tengasco, Inc. and Subsidiaries~~

~~Notes to Unaudited Condensed Consolidated Financial Statements~~

~~(10) Commitments and Contingencies~~

~~Cost Reduction Measures~~

~~Commencing in the quarter~~ ended March 31, ~~2015~~2021 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors. These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a thirty-day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel. In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty-day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors. 2020:


	Three Months Ended March 31,			Six Months Ended March 31,
		2021		2020		2021		2020

Continuing Operations:
Net income (loss) (in thousands) - Diluted		$	(33,272)	$	75,053	$	(41,213)	$	68,212
Plus: Dividends on preferred units		(574)		(877)		(1,491)		(1,741)
Net income (loss) attributable to common shareholders/unitholders (in thousands) - Basic		$	(33,846)	$	74,176	$	(42,704)	$	66,471

Basic weighted-average common units outstanding		14,542,273		12,457,273		13,574,767		12,446,010
Effecting of dilutive securities:
Series A preferred units		0		3,969,276		0		3,940,084
Restricted units		0		59,726		0		49,151
Diluted weighted-average common units outstanding		14,542,273		16,486,275		13,574,767		16,435,245
Continuing Operations:
Basic net income (loss) per common unit		$	(2.33)	$	5.95	$	(3.15)	$	5.34
Diluted net income (loss) per common unit		$	(2.33)	$	4.55	$	(3.15)	$	4.15

For the ~~period January 1, 2015 through September 30,~~three and six months ended March 31, 2021 and 2020, the ~~reductions~~following units were ~~approximately $390,000. Of~~excluded from the ~~$390,000, approximately $77,000 would be paid in the Company’s common stock. The $77,000 value represents approximately 94,000 common shares valued at $0.82~~calculation of diluted net income (loss) per ~~share which represents the closing price on September 30, 2020. The Company has not accrued any liabilities associated with these compensation reductions.~~unit due to their anti-dilutive effect:


	Three Months Ended March 31,		Six Months Ended March 31,
	2021	2020	2021	2020


Restricted units	103,276	138,298	70,764	148,873

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

17.Commitments and Contingencies

Legal ~~Proceedings~~

Matters

On May 14, 2020 the Company, associated with the predecessor Tengasco entity, received notice of ~~three~~3 orders (the “Orders”) issued by the Regional Director of the Bureau of Safety and Environmental Enforcement (“BSEE”) of the Department of the Interior dated May 13, 2020, stating that the Company, together with a group of several other named parties, were being looked to by the BSEE to perform the decommissioning of facilities on three Gulf of Mexico leases owned by Hoactzin Partners, L. P. (“Hoactzin’) and other lessees due to Hoactzin’s default in its lease obligations to decommission such facilities. No monetary amount was sought or described in the Orders. Hoactzin is controlled by Peter E. Salas, the chairman of ~~the Company’s~~Tengasco’s Board of ~~Directors.~~Directors prior to the Merger. Management’s assessment of the likelihood of a loss is remote as the Company believes it has available defenses to the Orders. On August 21, 2020, the bankruptcy court in the Northern District of Texas in Dallas entered an agreed order requiring Hoactzin, the surety on Hoactzin’s bonds, and seven other working interest owners (a group not including the Company) to complete all the necessary decommissioning on all of Hoactzin’s facilities and to prepay all anticipated expenses, including insurance premiums and a contingency reserve, estimated to be necessary to do so. The bankruptcy trustee has reported that all funds to be paid have been received from all parties to the agreed order. Decommissioning is proceeding under the direction of the bankruptcy trustee and approved contractors under the control of the bankruptcy court. Accordingly, it is anticipated that all work contemplated by the Orders will be completed by, and at the expense of, other persons and the relief sought in the Orders for the Company to perform the work will at that time ~~be moot as~~have no impact to the Company.

In response to the announcement that Tengasco and REP LLC were engaging in a business combination, on December 2, 2020 a purported shareholder of Tengasco filed a lawsuit against Tengasco and the members of the Tengasco board of directors in the United States District Court, Southern District of New York, captioned Luis A. Nieves Cortes v. Tengasco Inc., et al., Case No. 1:20-cv-10111-LAP (which we refer to as the “Cortes complaint”). On December 8, 2020 a purported shareholder of Tengasco filed a lawsuit against Tengasco, the members of the Tengasco board of directors, and Mike Rugen, Tengasco’s CFO/Interim CEO, in the United States District Court, Southern District of New York, captioned Sarah King v. Tengasco, Inc., et al., Case No. 1:20-cv-10343 (which we refer to as the “King complaint”). On December 10, 2020 a purported shareholder of Tengasco filed a lawsuit against Tengasco, the members of the Tengasco board of directors, Antman Sub, LLC and Riley Exploration Permian, LLC in the United States District Court, District of Delaware, captioned Lewis D. Baker v. Tengasco, Inc., et al., Case No. 1:20-cv-01681-UNA (which we refer to as the “Baker complaint”). On December 31, 2020 a purported shareholder of Tengasco filed a lawsuit against Tengasco and the members of the Tengasco board of directors in the United States District Court, Southern District of New York, captioned Lara Gaudio v. Tengasco, Inc., et al., Case No. 1:20-cv-11114-UA (which we refer to as the “Gaudio complaint”). On February 4, 2021 a purported shareholder of Tengasco filed a lawsuit against Tengasco and the members of the Tengasco board of directors in the United States District Court, District of Colorado, captioned Robert Wilhelm v. Tengasco, Inc., et al., Case No. 1:21-cv-00348 (which we refer to as the “Wilhelm complaint” and together with the Cortes complaint, the King complaint, the Baker complaint, and the Gaudio complaint, the “federal law complaints”). The plaintiffs in the federal law complaints generally claimed 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. In addition, the plaintiff in the King complaint claims that the individual defendants breached their fiduciary duties of candor and disclosure. The plaintiffs sought, among other things, injunctive relief to prevent consummation of the merger until the alleged disclosure violations were cured, damages in the event the merger was consummated, and an award of attorney's fees and costs. While Tengasco and REP LLC believed the previous disclosures were complete and disagreed with the plaintiffs, Tengasco filed a Form 8-K that included certain additional requested disclosures. Plaintiffs dismissed all of the federal law complaints.

~~In all other respects,~~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 March 31, 2021 and September 30, 2020. Management believes it is remote that the impact of such matters will have a ~~party~~materially adverse effect on the Company’s financial position, results of operations, or cash flows.

Environmental Matters

The Company is subject to ~~any pending material legal proceeding. To the knowledge of management, no~~various federal, state orand local ~~governmental agency is presently contemplating any proceeding against~~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 ~~which would have a result materially adverse~~ to remove or mitigate the ~~Company. To the knowledge of management, no director, executive officer or affiliate~~environmental effects of the disposal or release of petroleum or chemical

RILEY EXPLORATION PERMIAN, INC.

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS – (Continued)

(Unaudited)

substances at various sites. The Company ~~or owner~~recorded 0 environmental liabilities as of ~~record or beneficial owner~~March 31, 2021 and September 30, 2020.

18.Subsequent Events

Effective April 1, 2021, the Company granted $4.6 million of ~~more than 5%~~restricted shares and stock awards (196,342 restricted shares determined on April 1, 2021) under the 2021 LTIP to certain employees and executives in accordance with the March 15, 2021 board consent. See further discussion in Note 13 - Share-Based and Unit-Based Compensation.

On April 2, 2021, the Company closed on a sale of the Kansas Reporting Unit for an agreed upon purchase price of $3.5 million, plus approximately $0.2 million of closing adjustments. See further discussion in Note 5 - Oil and Natural Gas Properties.

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of the Company’s financial condition and results of operations should be read in conjunction with the Company’s unaudited condensed consolidated financial statements and related notes thereto presented in this report as well as the Company’s audited consolidated financial statements and related notes included in the Company's current report on Form 8-K/A filed on April 22, 2021. The following discussion contains “forward-looking statements” that reflect the Company’s future plans, estimates, beliefs and expected performance. The Company’s actual results could differ materially from those discussed in these forward-looking statements. See "Cautionary Statements Regarding Forward-Looking Statements", “—Forward-Looking Statements and Risk” and “Part II. Item 1A. Risk Factors”.

Overview

We operate in the upstream segment of the oil and gas industry and are focused on steadily growing conventional reserves, production and cash flow through the acquisition, exploration, development and production of oil, natural gas and natural gas liquids (“NGLs”) primarily in the Permian Basin. The Company’s activities are primarily focused on the San Andres Formation, a shelf margin deposit on the Central Basin Platform and Northwest Shelf.

Financial and Operating Highlights

Financial and operating results reflect the following:

•Completed Merger on February 26, 2021

•Increased total equivalent production by 11% to 8.3 MBoe/d for the three months ended March 31, 2021, as compared to the same period in 2020, despite significant reductions in capital expenditures and production outages due to two severe storms

•Realized average composite price on commodities of $49.12 per Boe during the second quarter of 2021, representing a 37% increase over the same period in 2020

•Realized average composite price on commodities of $42.68 per Boe, including derivative settlements, during the second quarter of 2021, representing a 3% decrease over the same period in 2020

•Generated cash flow from operations of $38.1 million for the six months ended March 31, 2021

•Incurred total capital expenditures of $17.1 million primarily related to oil and natural gas drilling and completion activity for the six months ended March 31, 2021, representing a significant decrease of 49% compared to the same period for 2020

•Paid cash common ~~stock~~dividends of $3.8 million during the three months ended March 31, 2021; announced latest dividend of $0.28 per share with a record date of April 16, 2021, which was paid May 7, 2021, for a total of $5.0 million

•Exited the second quarter with $10.1 million in cash and $97.5 million drawn on our credit facility

Recent Developments

Market Conditions and Commodity Prices

The COVID-19 pandemic and the measures being taken to address and limit the spread of the virus significantly reduced global economic activity, resulting in a significant decline in the demand for and prices of crude oil and condensate, natural gas liquids (NGLs) and natural gas. Additionally, production disagreements among members of the Organization of Petroleum Exporting Countries and certain other oil exporting countries (OPEC+), led to significantly lower commodity prices during March and April 2020, including historically low oil prices. Subsequently, members of OPEC+ reached agreements to limit oil production with phased returns of production over time. Questions over individual member compliance with such agreements, as well as the duration and potential extensions of such production cuts, has led to uncertainty over supply and demand balances. These factors caused a swift and material deterioration in commodity prices for a majority of 2020.

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

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

In response to the 2020 market conditions described above, and in an effort to preserve liquidity, the Company updated its 2020 capital and operating plan to significantly reduce drilling and completion activity and decrease its capital expenditures. Additionally, the Company quickly made significant cuts in G&A with reductions in workforce, information technology, and professional fees. The Company further preserved liquidity by reducing cash dividends on common units by 50%.

On December 15, 2020 our gas gatherer and processor in Yoakum County, TX, Stakeholder Midstream announced that it had acquired Santa Fe Midstream's Gas Gathering and Processing Assets (the "Santa Fe Assets") located in Yoakum County. Shortly thereafter they began to integrate the newly acquired assets with their Campo Viejo Processing Plant and gathering system. When completed in early February 2021, this integration allowed Riley Permian to commence selling incremental volumes of natural gas and natural gas liquids that were previously being flared. Further, the increase in natural gas and natural gas liquids as a percentage of our production stream is a ~~party adverse~~direct result of additional gas gathering and processing capabilities, and does not represent a change in the gas oil ratio ("GOR"). Increase in natural gas and natural gas liquids deliveries 30% and 39%, respectively, or 52.5 MBoe first quarter to second quarter.

In February 2021, Winter Storm Uri was a major coast-to-coast storm that produced snow and damaging ice from the Northwest into the South, Midwest and interior Northeast which significantly increased demand for natural gas from record low temperatures across the United States. The state of Texas experienced record snow levels and experienced the coldest temperatures in decades for certain cities. These conditions resulted in challenges to the ~~Company or has~~producing wells in Texas by causing freeze-offs (temporary interruptions in production caused by cold weather). The freeze-offs coupled with increased national demand caused significant increases in natural gas spot prices. As a ~~material interest adverse to~~result of Winter Storm Uri, the Company experienced production outages which resulted in ~~any proceeding.~~an estimated reduction of 18 net MBoe (or an average of 3.7 MBoe/d per day) over a 5-day period in February 2021.

~~(11) Subsequent Events~~

Recent Transactions

On the Closing Date, Riley Permian consummated the previously announced merger pursuant to that certain Merger Agreement, dated as of October 21, 2020, by and among Tengasco, Merger Sub, and REP LLC, as amended by Amendment No. 1 to Agreement and Plan of Merger, dated as of January 20, 2021, by and among Tengasco, Merger Sub and REP, LLC. Pursuant to the ~~Company, Antman~~terms of the Merger Agreement, a business combination between the Registrant and REP LLC was effected through the merger of Merger Sub with and into REP LLC, ~~a newly-formed Delaware limited~~with REP LLC surviving as the surviving company and as a wholly-owned subsidiary of the ~~Company (“Merger Sub”), and Riley Exploration - Permian, LLC a delaware limited liability company (“Riley”), entered~~Registrant (collectively, with the ~~Merger Agreement pursuant to which Merger Sub will be merged with and into Riley, with Riley surviving the Merger as a wholly owned subsidiary of the Company.~~ ~~On the terms and subject to the conditions set forth~~other transactions described in the Merger Agreement, ~~upon consummation~~the “Merger”). On the Closing Date, the Registrant changed its name from Tengasco, Inc. to Riley Exploration Permian, Inc. Our organizational structure includes wholly-owned consolidated subsidiaries through which our operations are conducted, including without limitation, REP, LLC and Riley Permian Operating Company, LLC. Immediately following the closing of the Merger, ~~each common unit~~the former members of ~~Riley issued and outstanding immediately prior to the effective time~~REP LLC owned 95% of the ~~Merger (other than cancelled units (as defined~~Company and the former Tengasco stockholders owned the remaining 5% of the Company.

On March 10, 2021, the Company entered into a PSA to sell the Kansas Reporting Unit for an agreed upon purchase price of $3.5 million (subject to certain adjustments), contingent upon certain conditions to closing. The effective date of the sale was March 1, 2021 and the sale closed on April 2, 2021 for the agreed upon purchase price, plus approximately $0.2 million of net closing adjustments. As of March 31, 2021, the assets and liabilities associated with these divested assets were classified as held for sale in the ~~Merger Agreement))~~accompanying condensed consolidated balance sheet.

2021 Capital and Operating Plan

We expect our fiscal 2021 capital budget to be approximately $54 million to $56 million, which we believe is consistent with our capital allocation framework, and which we believe will be ~~converted into~~funded entirely by operating cash flow.

Comparison for the ~~right to receive: (a) 97.796467 shares~~Three and Six Months Ended March 31, 2021 and 2020

The following table provides a summary of the Company’s ~~common stock (together with any cash~~sales volumes, average prices and certain operating expenses on a per BOE basis:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
Total Sales Volumes:

Oil (MBbls)	543		554		1,090		1,077
Natural Gas (MMcf)	602		383		1,063		762
NGL (MBbls)	103		62		177		119
Total (MBoe)1	746		680		1,445		1,323

Average Daily Sales Volumes:

Oil sales (Bbl/d)	6,031		6,086		5,988		5,884
Natural gas sales (Mcf/d)	6,683		4,214		5,841		4,166
Natural gas liquids sales (Bbl/d)	1,148		681		975		653
Total (BOE/d)1	8,293		7,469		7,937		7,231

Average Sales Price1:

Oil sales (per Bbl)	$	56.71	$	44.42	$	48.53	$	49.59
Oil sales with derivative settlements (per Bbl)2	51.70		53.33		50.78		54.69
Natural gas sales (per Mcf)	7.51		(0.24)		4.36		(0.36)
Natural gas sales with derivative settlements (per Mcf)2	7.72		(0.24)		4.48		(0.36)
Natural gas liquids sales (per Bbl)	13.16		(2.41)		8.72		(2.26)
Natural gas liquids with derivative settlements (per Bbl)2	13.16		(2.41)		8.72		(2.26)
Average price per BOE1,2	49.12		35.84		40.89		39.94
Average price per BOE including derivative settlements1,2	45.64		43.10		42.68		44.09

Expenses per BOE1:

Lease operating expenses	$	9.07	$	8.87	$	8.01	$	8.89
Production taxes	2.60		1.70		2.08		1.90
Exploration expenses	7.33		2.57		4.08		1.87
Depletion, depreciation, amortization, and accretion	8.38		7.88		8.47		8.31
General and administrative expenses	10.11		5.47		7.20		5.36
General and administrative expenses, net of gross profit on contract services3	9.42		4.13		6.54		4.00
Transaction costs	2.90		0.04		2.22		0.02

1 One BOE is equal to ~~be paid~~six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This is an energy content correlation and does not reflect value or price relationship between the commodities.

2 Average prices shown in ~~lieu~~table reflect prices both before and after the effects of ~~fractional shares~~REXP’s settlements of ~~the Company Common Stock) and (b) any dividends or other distributions to which the holder of a Riley common unit becomes entitled to upon the surrender~~our commodity derivative contracts. REXP’s calculation of such ~~Riley common unit~~effects includes both gains or losses on cash settlements for commodity derivatives. The impact of these cash settlements are included in ~~accordance with~~other income and expense on the ~~Merger Agreement.~~Company’s Statement of Operations.

3 General and administrative expenses shown after the effect of gross profit from contract services derived from management services agreements.

~~Additional information regarding~~

Oil and Natural Gas Revenues

The Company’s total oil and natural gas revenue, net increased 51% and 12% for the ~~Merger~~three and six months ended March 31, 2021, respectively, as compared to total oil and natural gas revenues for the ~~Merger Agreement can be found~~same period of 2020. This increase for the three and six month periods was driven by a combination of higher composite price and higher equivalent volume. The Company’s oil and natural gas sales, net in ~~(a)~~its financial statements do not include the ~~press release issued~~effects of derivatives as those effects are included within other income.

The Company’s realized average composite price on commodities of $49.12 per Boe for the second quarter of 2021 increased by $13.28 per Boe, or 37%, over the ~~Company~~realized average composite price of $35.84 per Boe for the same period of 2020. The Company’s realized average composite price on ~~October 21, 2020 and (b) the Current Report on Form 8-K filed by the Company on October 22, 2020.~~

~~Table~~commodities of ~~Contents~~

~~ITEM 2.~~

~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~

~~Results of Operations and Financial Condition~~

~~During~~$40.89 per Boe, for the first ~~nine~~six months of 2021 increased by $0.95 per Boe, or 2%, over the realized average composite price of $39.94 per Boe for the same period of 2020. The Company's realized price increased across all commodities, which was driven by a general improvement in supply/demand fundamentals over the same period of 2020, 92.4MBbl gross of oil were sold from the Company’s properties. Of the 92.4MBbl sold, 67.0MBbl were net to the Company after required payments to all of the royalty interests and the one remaining drilling program participant.as well as short-term, significant price increases experienced during Winter Storm Uri. The Company’s ~~net sales~~average daily production increased by 11% and 10% to 8.3 MBoe per day and 7.9 MBoe per day for the three and six months ended March 31, 2021, respectively, from ~~its properties during~~7.5 MBoe per day and 7.2 MBoe per day for the ~~first nine months~~same periods in 2020.

Oil revenues for the second quarter of ~~2020 of 67.0MBbl of oil compares~~2021 increased $6.2 million, or 25%, to ~~net sales of 72.1MBbl of oil during~~$30.8 million from $24.6 million for the ~~first nine months of 2019.~~same period in 2020. The ~~Company’s net revenue from its oil and gas properties~~increase was ~~$2.3 million during the first nine months of 2020 compared to $3.8 million during the first nine months of 2019. This decrease in net revenue was primarily~~ due to ~~an $1.2 million reduction related to~~ a $18.12 per barrel decrease in the average oil price from $52.09 per barrel during the first nine months of 2019 to $33.97 per barrel during the first nine months of 2020, and a $269,000 reduction related to a 5.1MBbl decrease in sales volumes. The 5.1MBbl decrease in sales volumes was primarily related to lower sales on the Albers, BSU, Liebenau, Veverka D leases related to natural production declines, partially offset by sales from the Zimmerman well that was completed at the beginning of 2020.

~~Comparison of the Quarters Ended September 30, 2020 and 2019~~

The Company reported a net loss of $(813,000) or $(0.08) per share of common stock during the third quarter of 2020 compared to net loss of $(182,000) or $(0.02) per share of common stock during the third quarter of 2019. The $631,000 decrease in net income was primarily due to an $450,000 decrease in revenues, and a $388,00027% increase in ~~general and administrative expenses,~~realized price partially offset by a ~~$167,000~~decrease of 11 MBbls or 2% in production volume. Including derivative settlements, the average realized price decreased by $1.63 per Bbl or 3%. The decrease in total production ~~costs and taxes and a $40,000 decrease~~was partially attributable to there being one less day in ~~depreciation, depletion, and amortization costs.~~

~~The Company recognized $765,000 in revenues during~~ the ~~third~~first quarter of 2021 as compared to the same quarter of 2020 (which was a leap year); average daily production decreased by less than 1% or 55 Bbls per day in the second quarter 2021 compared to ~~$1.2 million~~the same period in 2020. Further, the Company significantly reduced drilling and completion activity during the ~~third~~second quarter of ~~2019. The $450,000~~2021 as compared to the same period in 2020, including a 40% decrease in capital expenditures. Finally, the Company experienced production outages during two severe storms. Production outages experienced during Winter Storm Uri resulted in a reduction of 14.6 net MBbls (or an average of 2.9 MBbls per day) over a 5-day period in February 2021.

Revenues derived from the sale of natural gas and natural gas liquids for the second quarter of 2021 increased by a combined $6.1 million to $5.9 million from negative $0.2 million for the same period in 2020. Revenues derived from the sale of natural gas and natural gas liquids for the first six months of 2021 increased by a combined $6.7 million to $6.2 million from negative $0.5 million for the same period in 2020. These increases were driven by a combination of significantly higher prices and volume. Higher prices for both natural gas and natural gas liquids were driven by a general improvement in supply/demand fundamentals over the same period in 2020, as well as short-term, significant price increases experienced during Winter Storm Uri. The Company’s natural gas and natural gas liquids sales volumes increased for the second quarter of 2021 by 219 MMcf (57% increase over second quarter 2020) and 41 MBbls (66% increase over second quarter 2020), respectively, to 602 MMcf and 103 MBbls, respectively. The Company’s natural gas and natural gas liquids sales volumes increased for the first six months of 2021 by 301 MMcf (40% increase over first six months of 2020) and 58 MBbls (49% increase over first six months of 2020), respectively, to 1,063 MMcf and 177 MBbls, respectively. The increased production volume in both natural gas and natural gas liquids volumes were attributable primarily to a significant increase in gas processing capacity available from the Company’s midstream gathering and processing partner, Stakeholder Midstream, as a result of the acquisition of an additional gas processing plant by Stakeholder Midstream. The increase in natural gas and natural gas liquids as a percentage of the Company's total equivalent production is a direct result of additional gas gathering and processing capabilities, and does not represent a change in the GOR.

The following tables present oil and natural gas revenues disaggregated by product:


	March 31, 2021		March 31, 2020		Change		% Change
	($ in thousands)
Three Months Ended
Oil sales	$	30,784	$	24,598	$	6,186	25	%
Natural gas sales	4,516		(93)		4,609		4,956	%

Natural gas liquids sales	1,359		(149)		1,508		1,012	%

Oil and natural gas sales, net	$	36,659	$	24,356	$	12,303	51	%


Six Months Ended
Oil sales	$	52,891	$	53,396	$	(505)	(1)	%
Natural gas sales	4,635		(271)		4,906		1,810	%
Natural gas liquids sales	1,547		(270)		1,817		673	%
Oil and natural gas sales, net	$	59,073	$	52,855	$	6,218	12	%

The following tables present sales volumes for the Company’s continuing operations:


	March 31, 2021	March 31, 2020	Change	% Change
	($ in thousands)
Three Months Ended:
Oil (MBbls)	543	554	(11)	(2)	%
Natural gas (MMcf)	602	383	219	57	%
Natural gas liquids (MBbls)	103	62	41	66	%
Total (MBoe)4	746	680	66	10	%

Average net sales (BOE/d)4,5	8.3	7.5	0.8	11	%

Six Months Ended:
Oil (MBbls)	1,090	1,077	13	1	%
Natural gas (MMcf)	1,063	762	301	40	%
Natural gas liquids (MBbls)	177	119	58	49	%
Total (MBoe)4	1,445	1,323	122	9	%

Average net sales (BOE/d)4,5	7.9	7.2	0.7	10	%

4 One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This is an energy content correlation and does not reflect value or price relationship between the commodities.

5 Average net sales (BOE/d) was derived by dividing the total MBoe by 91 days and 90 days for the three months ended March 2021 and 2020, respectively. Average net sales (BOE/d) was derived by dividing the total MBoe by 182 days and 181 days for the six months ended March 2021 and 2020, respectively.

Realized Prices on Oil and Natural Gas Sales

The following table presents the Company’s average realized commodity prices, as well as the effects of derivative settlements:


	Three Months Ended March 31,						Six Months Ended March 31,
	2021			2020			2021			2020
	($ in thousands)
Oil



NYMEX WTI Average ($/Bbl)	$	57.84		$	46.17		$	50.25		$	51.57
Differential ($/Bbl) to Average NYMEX WTI	1.13			1.75			1.72			1.98
Average Realized Price ($/Bbl)	56.71			44.42			48.53			49.59
Averaged Realized Price as a % of Average NYMEX WTI 6	98		%	96		%	97		%	96		%
Average Realized Price, with derivative settlements ($/Bbl)	51.70			53.33			50.78			54.69

Natural Gas 7



NYMEX Henry Hub Average ($/MMBtu)	$	2.69		$	1.95		$	2.68		$	2.23
Differential ($/Mcf) to Average NYMEX Henry Hub6	(4.82)			2.19			(1.68)			2.59
Average Realized Price ($/Mcf)	7.51			(0.24)			4.36			(0.36)
Averaged Realized Price as a % of Average NYMEX Henry Hub	279		%	(12)		%	163		%	(16)		%
Average Realized Price, with derivative settlements ($/Mcf)	7.72			(0.24)			4.48			(0.36)

Natural Gas Liquids7

Average Realized Price ($/Bbl)	$	13.16		$	(2.41)		$	8.72		$	(2.26)
Averaged Realized Price as a % of Average NYMEX WTI	23		%	(5)		%	17		%	(4)		%

BOE (Barrel of Oil Equivalent)

Average price per BOE6	$	49.12		$	35.84		$	40.89		$	39.94
Average price per BOE with derivative settlements6,8	45.64			43.10			42.68			44.09

While quoted NYMEX oil and natural gas prices are generally used as a basis for comparison within the Company’s industry, the prices the Company receives are affected by quality, energy content, location and transportation differentials for these products.

6 One BOE is equal to six Mcf of natural gas or one Bbl of oil or NGL based on the approximate energy equivalency. This

is an energy content correlation and does not reflect value or price relationship between the commodities.

7 Realized prices are reflected at net of the deduction of gathering, processing and transportation costs.

8 Average prices shown in table reflect prices both before and after the effects of our settlements of REP’s commodity

derivative contracts. REP’s calculation of such effects includes both gains or losses on cash settlements for commodity

derivatives.

Contract Services - Related Party Revenue

The following tables present the Company's gross profit for related party transactions:


	Three Months Ended March 31,						Six Months Ended March 31,
	2021			2020			2021			2020
	($ in thousands)
Contract services – related parties	$	600		$	1,050		$	1,200		$	2,100
Cost of contract services - related parties	91			138			239			306
Gross profit - related parties	$	509		$	912		$	961		$	1,794

Gross profit percentage - related parties	85		%	87		%	80		%	85		%

The Company’s contract services – related parties revenue is derived from master services agreements with related parties to provide certain administrative support services. See Note 9 – Transactions with Related Parties to the Company's unaudited condensed consolidated financial statement included herein for more information.

The Company's contract services - related parties gross profit decreased for the three and six months ended March 31, 2021 primarily due to the restructuring of the monthly fee in the fourth quarter of fiscal 2020. The monthly fee decreased by $150 thousand per month.

Lease Operating Expenses

The Company’s lease operating expenses ("LOE") increased by 12%, or $0.8 million, to $6.8 million or $9.07 per Boe for the three months ended March 31, 2021, from $6.0 million or $8.87 per Boe for the three months ended March 31, 2020. The net increase in LOE when compared to the three months ended March 31, 2020 is attributable to a ~~$318,000 reduction~~combination of factors, including an increase of $0.6 million due to higher equivalent production, an increase of $0.4 million related to ad valorem taxes, an increase of $1.0 million related to a ~~$15.15 per barrel decrease in the average oil price from $51.18 per barrel during the third quarter of 2019 to $36.03 per barrel during the third quarter of 2020,~~non-recurring workover expense, and a ~~$133,000 reduction~~decrease of $1.2 million due to general performance improvement of recurring LOE. The Company’s non-recurring workover expense was related to a ~~2.6MBbl decrease~~downhole failure on a salt-water disposal well, which led to an increase in ~~oil sales volumes. The 2.6MBbl decrease~~LOE of 21% or approximately $1.34 per Boe. Excluding this non-recurring workover, LOE for the three months ended March 31, 2021 would have been lower than the same period in ~~sales volumes was primarily related~~2020 by $1.38 per Boe, or 16%, at an estimated $7.49 per Boe.

Production Tax Expense

Production taxes increased to ~~lower sales on~~$1.9 million and $3.0 million for the ~~Albers, Dick A, Liebenau,~~three and ~~Stahl leases related~~six months ended March 31, 2021, respectively, due to ~~natural~~increases in commodity sales. On a per unit basis, production ~~declines and timing of crude pickups~~taxes increased by $0.90 per Boe or 53% to $2.60 per Boe for the ~~purchases, partially offset by sales~~second quarter 2021 from $1.70 per Boe for the ~~Zimmerman well that was completed at the beginning of 2020.~~

~~General and administrative costs increased $388,000 from $297,000 during the third quarter of 2019 to $685,000 during the third quarter of~~same period in 2020. This increase was ~~primarily due to costs incurred during~~driven by the ~~third~~significantly higher commodity prices realized in the second quarter of ~~2020 related~~2021, including the short-term high prices of natural gas and natural gas liquids attributable to Winter Storm Uri.

Exploration Expense

Exploration expense increased to $5.5 million and $5.9 million, respectively, for the ~~announced transaction with Riley Exploration – Permian, LLC. See Part II, Item 5, Other Information.~~

~~Production costs~~three and ~~taxes decreased $167,000~~six months ended March 31, 2021. On a per unit basis, exploration expense increased by $4.76 per Boe to $7.33 per Boe for the three months ending March 31, 2021, from ~~$913,000 during~~$2.57 per Boe for the ~~third quarter of 2019~~same period in 2020; exploration expense increased by $2.21 per Boe to ~~$746,000 during~~$4.08 per Boe for the ~~third quarter of 2020. This decrease was primarily due to lower well repair costs and a change~~six months ending March 31, 2021, from $1.87 per Boe for the same period in ~~the oil inventory adjustment.~~

Depreciation, depletion, and amortization costs decreased $40,000 from $186,000 during the third quarter of 2019 to $146,000 during the third quarter of 2020. This decrease was primarily related to lower depletion expense on the Company’s oil properties.

~~Comparison of the Nine Months Ended September 30, 2020 and 2019~~

The Company reported a net loss of $(1.9 million) or $(0.18) per share of common stock during the first nine months of 2020 compared to a net loss of $(269,000) or $(0.03) per share of common stock during the first nine months of 2019. The $1.6 million decrease in net income was primarily due to an $1.5 million decrease in revenues, a $411,000 increase in general and administrative expenses, and a $41,000 decrease in gain on sale of assets, partially offset by a $205,000 decrease in production costs and taxes, and a $105,000 decrease in depreciation, depletion, and amortization costs.

The Company recognized $2.3 million of revenues during the first nine months of 2020 compared to $3.8 million during the first nine months of 2019. This decrease in net revenue was primarily due to an $1.2 million reduction related to a $18.12 per barrel decrease in the average oil price from $52.09 per barrel during the first nine months of 2019 to $33.97 per barrel during the first nine months of 2020, and a $269,000 reduction related to a 5.1MBbl decrease in sales volumes. The 5.1MBbl decrease in sales volumes was primarily related to lower sales on the Albers, BSU, Liebenau, Veverka D leases related to natural production declines, partially offset by sales from the Zimmerman well that was completed at the beginning of 2020.

~~General and administrative costs increased $411,000 from $913,000 during the first nine months of 2019 to $1.3 million during the first nine months of~~ 2020. This increase was ~~primarily~~driven by lease expirations of in the Champions and Montaña fields.

The following table summarizes exploration expense by field below:


	Champions		Montaña
Three Months Ended March 31, 2021
Exploration expense	$	2,900	$	2,503
Expired net acres	1,368		6,296
Net acres renewed after expiration	398		—

Six Months Ended March 31, 2021
Exploration expense	$	3,125	$	2,702
Expired net acres	1,467		7,201
Net acres renewed after expiration	486		—

Depletion, Depreciation, and Accretion Expense

The following table disaggregates the Company's depletion, depreciation, amortization and accretion expense:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)
Oil and natural gas depletion	$	6,119	$	5,239	$	12,010	$	10,730
Other property and equipment depreciation	110		105		188		209
ARO accretion	22		13		43		53
Total depletion, depreciation, and accretion expense	$	6,251	$	5,357	$	12,241	$	10,992

The Company’s depletion rate and expense increased for the three and six months ended March 31, 2021 due to higher production volumes and lower estimated proved reserves as used for the depletion calculation. The decrease in reserves used in the depletion calculation was due to the lower trailing, 12-month first day of the month weighted average price as reflected on the September 30, 2020 reserve report, as compared to the same weighted-average price calculated on September 30, 2019.

General and Administrative Costs

The following table disaggregates general and administrative costs ~~incurred~~shown after the effect of gross profit from contract services derived from management services agreements:


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)
Payroll and benefit costs	$	1,731	$	2,217	$	3,370	$	4,403
Non-payroll costs	965		1,297		1,771		2,330
Unit-based compensation expense	276		206		689		359
Stock-based compensation expense	4,571		—		4,571		—
Total general and administrative costs	7,543		3,720		10,401		7,092
Less: Gross profit - related party	509		912		961		1,794
G&A, net of gross profit - related party	$	7,034	$	2,808	$	9,440	$	5,298

G&A costs increased for the three and six months ended March 31, 2021 by 103% and 47%, as compared to the same periods for 2020, respectively. On a per unit basis, G&A expense increased by $4.64 or 85% per Boe to $10.11 per Boe for the three months ending March 31, 2021, from $5.47 per Boe for the same period in 2020; G&A expense increased by $1.84 or 34% per Boe to $7.20 per Boe for the six months ending March 31, 2021, from $5.36 per Boe for the same period in 2020. The largest contributor to the increase in G&A expense was additional compensation expense of $4.2 million related to restricted shares and stock awards given to certain executives and employees as a result of the Merger for the three and six months ended March 31, 2021. This expense was in part offset by the Company taking swift action to reduce G&A expense across several categories following the dual shocks of the COVID-19 pandemic and the OPEC+ production cut disagreements. The Company took measures to reduce its workforce during 2020 which contributed to a 22% and 23% decrease in payroll and benefit costs in G&A for the ~~third quarter of~~three and six month periods ended March 31, 2021 compared to the same periods for 2020, respectively. Non-payroll costs decreased by 26% and 24%, for the three and six month periods ended March 31, 2021 compared to the same periods for 2020, respectively, related to reductions in costs associated with information technology, legal and consulting expenses.

Transaction Costs

Transaction costs were $2.2 million and $3.2 million, respectively, for the three and six months ended March 31, 2021, respectively. The transaction costs are related to the ~~announced transaction with Riley Exploration – Permian, LLC.~~fees incurred for the Merger. See ~~Part II, Item 5, Other Information.~~Note 4 - Business Combinations to the Company's unaudited condensed consolidated financial statements included herein for further discussion of the Merger.

Interest Expense

~~Table of Contents~~

~~Gain on sale of assets~~Interest expense decreased ~~$41,000 from $45,000 during the nine months of 2019~~ to ~~$4,000 during the first nine months of 2020. This decrease was primarily related to gain on sale of equipment inventory to a third party during the first quarter of 2019.~~

~~Production costs~~$1.2 million and ~~taxes decreased $205,000 from $2.6 million during the first nine months of 2019 to~~ $2.4 million ~~during the first nine months of 2020. This decrease was primarily~~ due to lower ~~well repair costs, partially offset~~borrowings during the three and six months ended March 31, 2021.

Income Tax Provision

REP LLC became a taxable entity as a result of its Merger with Tengasco on February 26, 2021. See further discussion in Note 4 - Business Combinations. While REP LLC was organized as a limited liability company, taxable income passed through to its unit holders. Accordingly, a provision for federal and state corporate income taxes has been made only for the operations of REP LLC in the accompanying consolidated financial statements. Deferred income taxes are provided to reflect the future tax consequences or benefits of differences between the tax basis of assets and liabilities and their reported amounts in the financial statements using enacted tax rates. Upon the Merger into a corporation on February 26, 2021, the Company established a $13.6 million provision for deferred income taxes, of which $1.1 million is currently payable. The majority of this deferred tax liability was established by a change in tax status which primarily was attributable to the oil ~~inventory adjustment.~~and natural gas properties.


	Three Months Ended March 31,						Six Months Ended March 31,
	2021			2020			2021			2020
	($ in thousands)
Current expense (benefit)	$	1,143		$	—		$	778		$	—
Deferred expense (benefit)	13,088			—			12,938			—
Total expense (benefit)	$	14,231		$	—		$	13,716		$	—

Effective income tax rate	(74.7)		%	—		%	(49.9)		%	—		%

~~Depreciation, depletion~~

Derivative Arrangements

The following table presents the Company's derivative activities.


	Three Months Ended March 31,				Six Months Ended March 31,
	2021		2020		2021		2020
	($ in thousands)
Fair value of net asset (liability), beginning of period	$	2,839	$	(3,632)	$	21,921	$	14,959
Gain (loss) on derivatives	(24,903)		69,239		(38,812)		51,204
Settlements on derivatives	2,594		(4,936)		(2,579)		(5,492)
Fair value of net asset (liability), end of period	$	(19,470)	$	60,671	$	(19,470)	$	60,671

The unrealized loss for the three and ~~amortization costs decreased $105,000~~six months ended March 31, 2021 is due primarily to increasing crude oil future prices resulting from ~~$566,000~~the improving supply/demand balances. Whereas the realized gains during the ~~first nine~~three and six months ~~of 2019 to $461,000 during the nine months of 2020. This decrease~~ended March 31, 2020 was primarily derived from the significant decline in crude oil future pricing from the COVID-19 pandemic and the OPEC+ related disagreements. As commodity prices fluctuate, so will the income or loss the Company recognizes from its hedging activities. See Note 7 - Derivative Instruments to ~~lower depletion expense on~~ the ~~Company’s oil properties.~~Company's unaudited condensed consolidated financial statements included herein for more information of the Company's derivative arrangements.

Liquidity and Capital Resources

The Company’s primary sources of liquidity have been cash flows from operations and borrowings under the Company’s revolving credit facility. Cash flows are subject to a number of variables, including the level of oil and natural gas production and prices, and the significant capital expenditures required to more fully develop the Company’s properties. The Company last raised equity from investors in 2017.

~~At September 30,~~The following table summarizes the Company’s cash flows from continuing operations:


	Six Months Ended March 31,
	2021	2020
	($ in thousands)
Statement of Cash Flows Data from Continuing Operations:
Net cash provided by operating activities	38,146	36,252
Net cash used in investing activities	(16,825)	(37,741)
Net cash (used in) provided by financing activities	(13,152)	1,068

Operating Activities

Our cash flows from operating activities are sensitive to a variety of variables including commodity pricing and production. The Company plans to continue its practice of entering into hedging arrangements to reduce the impact of commodity price volatility on the Company’s cash flow from operations. Under this strategy, the Company expects to maintain an active hedging program which the Company believes will provide more certainty around its cash flow and returns, ability to fund its capital program and dividends on common stock. Additionally, the Company has certain covenants under its revolving credit facility to maintain active commodity price hedges.

The Company’s net cash provided by operating activities increased by $1.9 million for the six months ended March 31, 2021 as compared to the six months ended March 31, 2020, driven by an increase of $3.6 million from changes in working capital, partially offset by a $1.7 million decrease in cash flow from operating activities before working capital.

Investing Activities

The Company's cash flows used in investing activities decreased by $20.9 million or 55% to $16.8 million for the six months ended March 31, 2021 from $37.7 million for the same periods in 2020. The Company incurred $17.1 million of capital spending during the six months ended March 31, 2021 primarily related to drilling and completion costs, a decrease of $16.6 million, or 49%, as compared to the six months ended March 31, 2020. The Company drilled 11 gross (8.9 net) wells and completed 8 gross (5.5 net) wells during the six months ending March 31, 2021. Additionally, capital spending related to the acquisition of properties decreased by $3.8 million during the six months ended March 31, 2021 as compared

to the same period in 2020. Finally, the Company acquired cash of $0.9 million by way of the Tengasco transaction for the six months ended March 31, 2021, as compared to $0 acquired cash from business combinations for the same period in 2020.

Financing Activities

The Company's cash flows used in/provided by financing activities is influenced by the discretionary nature of our investing activities in order to line up with the Company's operating strategy.

As of March 31, 2021, the Company had a revolving credit facility with Prosperity Bank. This has historically been the Company’s primary source to fund working capital and capital spending. Under the credit facility, loans and letters of credit are available to the Company on a ~~revolving basis in an amount outstanding not to exceed the lesser of $50 million or the Company’s~~ borrowing base ~~in effect from time to time. As~~ of ~~September 30, 2020, the Company’s borrowing base was $3.1~~$135 million ~~subject to a credit limit based on current covenants~~and outstanding borrowings of ~~$1.442~~$97.5 million. ~~While the credit limit has not yet been formally reduced,~~Additionally, the Company has ~~experienced total negative EBITDA for the trailing 4 quarters ended September 30, 2020, which would result in a zero credit limit if the formal~~an available borrowing ~~base review would have occurred at September 30, 2020, therefore prohibiting any borrowings on the Company’s credit facility. The credit facility is secured by substantially all~~capacity of the Company’s producing and non-producing oil and gas properties. The credit facility includes certain covenants with which the Company is required to comply. At September 30, 2020, these covenants include the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x. At September 30, 2020, the interest rate on this credit facility was 3.75%. The Company was in compliance with all covenants during the quarter ended September 30, 2020. The Company had no outstanding borrowing under the facility$37.5 million as of ~~September 30, 2020 or December~~March 31, ~~2019. However, if~~2021. See “—Revolving Credit Facility” below for further discussion.

For the Company had borrowings under the credit facility at September 30, 2020, the Company would not have been in compliance with EBITDA related covenants as the Company reported negative EBITDA for the trailing four quarters ended September 30, 2020.

During the second quarter of 2020, the Company was approved by the Small Business Administration to receive a Paycheck Protection Program (“PPP”) loan in the amount of approximately $166,000. This loan was funded by Prosperity Bank in May 2020. The PPP loan is not part of the credit facility with Prosperity Bank as described above and therefore is not subject to the same terms as Company’s credit facility. The PPP loan has an interest rate of 1% with a maturity date of May 2022. There are no payments due during the first six months of the loan. After the six-month period has expired, all outstanding accrued interest is due. At that time, the remaining unforgiven portion of the loan will be due in 18 equal monthly installments of principal and interest. The Company applied for forgiveness of the amount due on the PPP loan based on spending the loan proceeds on eligible expenses as defined by statute. The Company anticipates that it will be eligible for forgiveness of the entire loan amount as the proceeds had been used for eligible expenses. On November 5, 2020, Prosperity Bank notified the Company that the PPP loan had been forgiven and the loan was closed. During the fourth quarter of 2020, the Company will record other income of $166,000 as a result of the PPP loan forgiveness.

~~Net~~ended March 31, 2021 cash used in ~~operating~~financing activities was ~~$(565,000) during the first nine months of 2020~~$13.2 million as compared to $371,000 provided by operating activities during the nine months of 2019. Cash flow provided by working capital was $765,000 during the first nine months of 2020 compared to $1,000 provided by working capital during the first nine months of 2019. The $936,000 decrease in cash provided by operating activities was primarily due to a $1.5$1.1 million decrease in revenues, and a $411,000 increase in general and administrative costs, partially offset by a $764,000 increase in cash flow provided by working capital, and a $205,000 decrease in production costs and taxes. Net cash used in investing activities was $(77,000) during the first nine months of 2020 compared to $36,000 provided by investing activities during the first nine months of 2019. This decrease in cash flow provided by investing activities was primarily due to proceeds from the sale of equipment inventory to a third party during 2019, and lower capital spending. Cash flow provided by financing activities during the ~~first nine~~six months ~~of 2020 was $132,000 compared to $(40,000)~~ended March 31, 2020. The Company’s net cash used inby financing activities ~~during~~in the ~~first nine~~six months ~~of 2019. This increase in cash provided by financing activities~~ended March 31, 2021 was primarily related to ~~funding received from~~$9.3 million cash payments of common and preferred dividends and $3.5 million net repayments of the ~~PPP loan program.~~credit facility.

Working Capital

~~Through November 2021,~~The Company’s working capital, which the Company ~~believes~~defines as current assets minus current liabilities, totaled a deficit of $29.6 million at March 31, 2021. This deficit is primarily attributable to $26.5 million of accrued liabilities and $14.3 million in current derivative liabilities. The Company may continue to incur working capital deficits in the future due to the amounts that accrue related to its ~~revenues as well as~~drilling program and changes in the value of its derivative assets and liabilities. The Company’s collection of receivables has historically been timely, and losses associated with uncollectible receivables have historically not been significant. The Company’s cash ~~on hand will be sufficient to fund operating costs and general and administrative expenses and to remain in compliance with its bank covenants. If revenues~~ and cash on hand are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company may be able to borrow funds against the credit facility depending on the borrowing base and credit limit. Because of the drop in oil prices during 2020 and resulting projected negative EBITDA, borrowing from the Company’s credit facility would result in non-compliance with current covenants, and would require a waiver on the EBITDA related covenants or a change in the covenants until such time as prices improve. In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

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~~Critical Accounting Policies~~

~~Effective January 1, 2019, the Company adopted ASU 2016-02~~ ~~Leases (Topic 842)~~.

~~Commitments and Contingencies~~

~~Cost Reduction Measures~~

~~Commencing in the quarter ended~~equivalents balance totaled approximately $10.1 million at March 31, ~~2015~~2021 and continuing into the quarter ended June 30, 2018, the Company implemented cost reduction measures including compensation reductions for each employee as well as members of the Board of Directors. These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a thirty-day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel. In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty-day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors. For the period January 1, 2015 throughwas $1.7 million at September 30, 2020, ~~the reductions were approximately $390,000. Of the $390,000, approximately $77,000 would be paid in the Company’s common stock.~~respectively. The ~~$77,000 value represents approximately 94,000 common shares valued at $0.82 per share~~cash balance as of March 31, 2021 was higher due to unanticipated timing of revenue collections from natural gas and natural gas liquid sales which ~~represents the closing price on September 30, 2020. The Company has not accrued any liabilities associated with these compensation reductions.~~

~~Legal Proceedings~~

~~On May 14, 2020~~ the Company received notice of three orders (the “Orders”) issued by the Regional Director of the Bureau of Safety and Environmental Enforcement (“BSEE”) of the Department of the Interior dated May 13, 2020, stating that the Company, together with a group of several other named parties, were being looked to by the BSEE to perform the decommissioning of facilities on three Gulf of Mexico leases owned by Hoactzin Partners, L. P. (“Hoactzin’) and other lessees due to Hoactzin’s default in its lease obligations to decommission such facilities. No monetary amount was sought or described in the Orders. Hoactzin is controlled by Peter E. Salas, the chairman of the Company’s Board of Directors. Management’s assessment of the likelihood of a loss is remote as the Company believes it has available defenses to the Orders. On August 21 2020, the bankruptcy court in the Northern District of Texas in Dallas entered an agreed order requiring Hoactzin, the surety on Hoactzin’s bonds, and seven other working interest owners (a group not including the Company) to complete all the necessary decommissioning on all of Hoactzin’s facilities and to prepay all anticipated expenses, including insurance premiums and a contingency reserve, estimated to be necessary to do so. The bankruptcy trustee has reported that all funds to be paid have been received from all parties to the agreed order. Decommissioning is proceeding under the direction of the bankruptcy trustee and approved contractors under the control of the bankruptcy court. Accordingly, it is anticipated that all work contemplated by the Orders will be completed by, and at the ~~expense~~end of ~~other persons~~March. The Company forecasts cash flows from operating activities, and ~~the relief sought in the Orders for the Company to perform the work will at that time be moot as to the Company.~~

In all other respects, the Company is not a party to any pending material legal proceeding. To the knowledge of management, no federal, state, or local governmental agency is presently contemplating any proceeding against the Company which would have a result materially adverse to the Company. To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficial owner of more than 5% of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding.

~~ITEM 3.~~

~~QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~

~~The Company’s Borrowing Base under its Credit Facility may be reduced by the lender~~.

~~The borrowing base~~availability under the Company’s revolving credit facility will be ~~determined~~sufficient to fund its working capital needs through May 2022. The Company expects that its pace of development, production volumes, commodity prices and differentials to NYMEX prices for the Company’s oil and natural gas production will be the largest variables affecting the Company’s working capital. Please see “—Liquidity and Capital Resources” above for factors relating to liquidity and current expectations.

Revolving Credit Facility

The Company's borrowing base was $135 million with outstanding borrowings of $97.5 million at March 31, 2021. See further discussion in Note 10 — Revolving Credit Facility to the Company's unaudited condensed consolidated financial statements included herein.

Critical Accounting Policies

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

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

The preparation of the Company’s financial statements requires the Company to ~~time by~~make estimates and assumptions that affect the ~~lender, consistent~~reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable

likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. The Company evaluates its estimates and assumptions on a regular basis. The Company bases its estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Significant areas requiring the use of assumptions, judgments and estimates include (1) oil and natural gas reserves; (2) cash flow estimates used in impairment testing of oil and gas properties; (3) depreciation, depletion, amortization and accretion, or DD&A; (4) asset retirement obligations; (5) assigning fair value and allocating purchase price in connection with ~~its customary~~business combinations; (6) accounts receivable; (7) valuation of commodity derivative instruments; (8) accrued liabilities; and (9) income tax provisions. Actual results may differ from these estimates and assumptions used in preparation of the Company’s unaudited condensed consolidated financial statements included herein.

Forward-Looking Statements and Risk

Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil, natural gas and ~~crude~~NGLs, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict.

There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can also affect these risks. Additionally, fluctuations in oil ~~lending practices. Reductions~~and natural gas prices, or a prolonged period of low prices, may substantially adversely affect the Company's financial position, results of operations, and cash flows.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The Company is exposed to market risk, including the effects of adverse changes in ~~estimates~~commodity prices and interest rates as described below. The primary objective of the following information is to provide quantitative and qualitative information about the Company's potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of the Company’s natural gas and crude oil reserves could result in a reduction in the Company’s borrowing base, which would reduce the amount of financial resources available under the Company’s revolving credit facility to meet its capital requirements. Such a reduction could be the result of lower commodity prices or production, inability to drill or unfavorable drilling results, changes in natural gas and crude oil reserve engineering, the lender’s inability to agree to an adequate borrowing base or adverse changes in the lenders’ practices regarding estimation of reserves. If cash flow from operations or the Company’s borrowing base decreasesmarket risk sensitive instruments were entered into for any reason, the Company’s ability to undertake exploration and development activities could be adversely affected. As a result, the Company’s ability to replace naturally declining production may be limited. In addition, if the borrowing base is reduced, the Company may be required to pay down its borrowings under the revolving credit facility so that outstanding borrowings do not exceed the reduced borrowing base. This requirement could further reduce the cash available to the Company for capital spending and, if the Company did not have sufficient capital to reduce its borrowing level, could cause the Company to default under its revolving credit facility. Because of the drop in oil prices during 2020 and resulting projected negative EBITDA, borrowing from the Company’s credit facility would result in non-compliance with current covenants, and would require a waiver on the EBITDA related covenants, or a change in the covenants, until such time as prices improve.

~~Table of Contents~~

purposes other than speculative trading.

Commodity Price Risk

The Company’s major market risk exposure is in the pricing ~~applicable to its~~that we receive for our oil, natural gas and NGL production, and primarily our oil production. ~~Realized pricing is primarily driven by the prevailing worldwide price~~Pricing for crude ~~oil. Historically, prices received for~~ oil, natural gas and ~~gas production~~NGLs have been volatile and unpredictable for several years, and ~~price~~this volatility is expected to ~~continue.~~continue in the future. The ~~average monthly Kansas~~prices we receive for our oil, ~~prices received during~~natural gas and NGLs depend on many factors outside of our control, such as the ~~first nine months~~strength of ~~2020 ranged from a low~~the global economy and global supply and demand for the commodities we produce.

The Company’s minimum hedging requirement was 50% as of ~~$15.26 per barrel to a high of $53.04 per barrel.~~

~~As of~~March 31, 2021. At March 31, 2021 and September 30, 2020, we had a net liability derivative position of $19.5 million and ~~December 31, 2019,~~a net asset derivative position $21.9 million, respectively, related to our price swaps and collars, to reduce price volatility associated with certain of our oil and natural gas sales. These instruments provide only partial price protection against declines in oil and natural gas prices and may partially limit our potential gains from future increases in prices. With respect to these fixed price swap contracts, the counterparty is required to make payment to the Company ~~had no open positions related~~if the settlement price for any settlement period is less than the swap price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. Our derivative ~~agreements relating~~contracts are based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate pricing and Crude Oil – Brent and with natural gas derivative settlements based on NYMEX Henry Hub and Waha Hub pricing.

Due to ~~commodities.~~this volatility, we have historically used, and we expect to continue to use, commodity derivative instruments, such as swaps and collars, to hedge price risk associated with a portion of our anticipated production. Our hedging instruments reduce, but do not eliminate, the potential effects of the variability in cash flow from operations due to fluctuations in oil and natural gas prices and provide increased certainty of cash flows for our drilling program and debt service requirements. See Note 10 - Revolving Credit Facility to the Company's unaudited condensed consolidated financial statements included hereinfor more information regarding the Company's revolving credit facility.

Counterparty and Customer Credit Risk

Our cash and cash equivalents are exposed to concentrations of credit risk. We manage and control this risk by investing these funds with major financial institutions. We often have balances in excess of the federally insured limits.

Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties. While we do not require counterparties to our derivative contracts to post collateral, we do evaluate the credit standing of such counterparties as it deems appropriate. Certain counterparties are financial institutions that participate as lenders in our revolving credit facility. The counterparties to our derivative contracts currently in place have investment grade ratings.

Our principal exposures to credit risk are through receivables resulting from joint interest receivables and receivables from the sale of our oil and natural gas production due to the concentration of our oil and natural gas receivables with very few significant customers. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Joint operations receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we intend to drill. We have little ability to control whether these entities will participate in our wells.

Interest Rate Risk

At September 30, 2020, the Company had balances on financing leases outstanding of approximately $100,000, no balance owed on its credit facility with Prosperity Bank, and $166,000 due on the Company’s PPP loan. As of ~~September 30, 2020, the~~March 31, 2021, we had $97.5 million of outstanding borrowings and an additional $37.5 million available under our revolving credit facility. We have entered into floating-to-fixed interest rate ~~on the credit facility was variable at a rate equal~~swaps to ~~prime plus 0.50% per annum. The Company’s credit facility~~manage interest rate ~~at September 30, 2020 was 3.75%. The Company’s financing leases of $100,000 have fixed interest rates ranging from 5.0%~~exposure related to ~~6.5%. The Company’s PPP loan interest rate was 1%.~~our revolving credit facility.

Cyber Security Risk

The ~~annual impact~~Company's reliance on ~~interest expense~~information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our business, financial condition or reputation and ~~the Company’s cash flows of a 10%~~ increase ~~in the interest rate on the credit facility would be approximately zero assuming borrowed amounts under the credit facility remained at the same amount owed as of September 30, 2020.~~ compliance challenges.

The Company ~~did not have any open derivative contracts relating to interest rates at September 30, 2020 or December 31, 2019.~~

~~Forward-Looking Statements and Risk~~

~~Certain statements in this report,~~relies on information technology systems, including statements of the future plans (including the Merger and the transaction contemplated by the Merger Agreement), objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions,internet sites, computer software, data hosting facilities and other ~~uncertainties, all~~hardware and platforms, some of which are ~~difficult~~hosted by third parties, to ~~predict.~~assist in conducting our business. Our information technology systems, as well as those of third parties we use in our operations, may be vulnerable to a variety of evolving cybersecurity risks, such as those involving unauthorized access or control, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions.

~~There~~Although we have implemented information technology controls and systems that are ~~numerous uncertainties inherent in projecting future rates~~designed to protect information and mitigate the risk of ~~production~~data loss and other cybersecurity risks, such measures cannot entirely eliminate cybersecurity threats, and the ~~timing of development expenditures. The total amount~~enhanced controls we have installed may be breached. If our information technology systems cease to function properly or ~~timing of actual future production may vary significantly from estimates. The drilling of exploratory wells can involve significant risks, including those related~~our cybersecurity is breached, we could suffer disruptions to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can also affect these risks. Additionally, fluctuations in oil and gas prices, or a prolonged period of low prices, may substantially adversely affect the Company’s financial position, results of operations, and cash flows.our normal operations.

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~~ITEM~~Item 4.

~~CONTROLS AND PROCEDURES~~

~~Evaluation of Disclosure~~ Controls and Procedures

~~The Company’s Chief Executive Officer~~Evaluation of disclosure controls and ~~Chief Financial Officer has evaluated the effectiveness of the Company’s~~procedures

Our management establishes and maintains disclosure controls and procedures (as defined in ~~Exchange Act Rules~~Rule 13a-15(e) and 15d-15(e)~~). Based on such evaluation,~~ under the ~~Company’s Chief Executive Officer and Chief Financial Officer has concluded~~Exchange Act) that ~~the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were adequate and effective~~are designed to ~~provide reasonable assurance~~ensure that information required to be disclosed by us in the ~~Company in~~ reports that ~~it files~~we file or ~~submits~~submit under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the ~~SEC’s~~Securities and Exchange Commission’s rules and forms. ~~The~~Such information is accumulated and communicated to our management, including our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), as appropriate to allow timely decisions regarding required disclosure. We have evaluated the effectiveness of ~~a system of~~our disclosure controls and procedures ~~is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about~~as of the ~~likelihood~~end of ~~future events,~~ the ~~soundness~~period covered by this report, with the participation of ~~internal controls,~~our CEO and ~~fraud. Due to such inherent limitations, there can be no assurance~~CFO, as well as other key members of our management. Based on this evaluation, our CEO and CFO concluded that ~~any system of~~our disclosure controls and procedures were not effective as of March 31, 2021 because of the material weakness in our internal control over financial reporting.

As of March 31, 2021, we have identified material weaknesses in our internal control over financial reporting. A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be ~~successful in preventing all errors~~prevented or ~~fraud, or in making all material information known~~detected on a timely basis. In particular, we had not yet designed an effective financial reporting process and did not complete thorough reviews of financial reports in a timely manner to allow for an appropriate level of analysis that would have identified these errors. These errors principally related to (i) accounting for stock-based compensation and our failure to record compensation expense for certain vested stock-based compensation grants in the ~~appropriate levels~~correct reporting period, (ii) accounting for dividend distributions and our failure to record a declared dividend in the reporting period in which the dividend was declared, (iii) accounting for derivative settlements, and (iv) controls over preparation and review of ~~management.~~the Company’s statement of cash flows were not effective. As of the date hereof, we have not fully re-designed, implemented and tested internal controls to remediate the material weaknesses.

Each of the material weaknesses could result in a misstatement of our financial statements or disclosures that would result in a material misstatement of our annual or interim consolidated financial statements that would not be prevented or detected.

Our management is in the process of developing its remediation plan to address the material weaknesses identified in the quarter. These plans are subject to ongoing management review. The material weaknesses identified above will not be considered remediated until our remediation efforts have been fully implemented and we have concluded that these controls are operating effectively. Consequently, if these or another material weakness or significant deficiencies occur in the future, it could affect the financial results that we report which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations.

Changes in ~~Internal Controls~~internal control over financial reporting

~~During the nine months ended September 30, 2020, there have been no changes to the Company’s system of~~The internal controls over financial reporting after the Merger are now the controls which REP LLC had in place prior to the Merger. There have been no other changes in our internal control over financial reporting that occurred for the quarter

PART II: OTHER INFORMATION

ending March 31, 2021 that have materially affected, or are reasonably likely to materially affect, ~~the Company’s system of controls~~our internal control over financial reporting. As ~~part~~noted above, the Company is in the process of developing a ~~continuing effort~~remediation plan to ~~improve~~address the material weaknesses described above.

PART II: OTHER INFORMATION

Item1. Legal Proceedings

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 ~~business processes, management~~estimates of the outcomes of these matters. The Company did not recognize any material liability as of March 31, 2021 and September 30, 2020. Management believes it is ~~evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes~~remote that the impact of such matters will have a materially adverse effect on the Company’s financial position, results of operations, or ~~accounting procedures.~~

~~PART II OTHER INFORMATION~~

~~ITEM 1.~~

~~LEGAL PROCEEDINGS~~

cash flows. See ~~ITEM 2, Management’s Discussion and Analysis of Financial Condition and Results of Operations,~~Note 17 – Commitments and Contingencies ~~Legal Proceedings, above~~to the Company’s unaudited condensed consolidated financial statements included herein for a further discussion of legal proceedings.

Item 1A. Risk Factors

Investors should carefully consider each of the following risk factors and all of the other information set forth in this ~~Report.~~

~~ITEM 1A.~~

~~RISK FACTORS~~

~~Refer~~Form 10-Q. If any of the following risks actually occur, our business, financial condition, and results of operations could be materially and adversely affected and we may not be able to ~~Item 1A Risk Factors~~achieve our goals. We cannot assure you that any of the following risks will not occur. Additional risks not presently known to us or that we currently deem immaterial also may materially affect our business. The risk factors included below supersede the "Risk Factors" from those described in ~~the Company’s~~our Annual Report on Form 10-K for the year ended December 31, ~~2019 filed~~2020.

Risks Related to Our Business, Operations, and Strategy

•An extended decline in commodity prices may adversely affect our business, financial condition, results of operations, ability to meet our capital expenditure obligations and financial commitments, and the value of our reserves.

• We may be unable to obtain required capital or financing on satisfactory terms in able to fund our exploration and development projects, which could lead to a decline in our reserves.

• Our exploration and development may not be profitable or achieve our targeted returns.

• Properties we acquire may not produce as projected, and may subject us to liabilities.

• Uncertainties could materially alter the occurrence or timing of drilling of our identified drilling locations.

• Reserve estimates depend on many assumptions that may turn out to be inaccurate.

• Using the latest available horizontal drilling and completion techniques involves risk and uncertainty.

• We are vulnerable to risks associated with operating in one major geographic area.

• We may not be able to access on commercially reasonable terms or otherwise truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas production.

• An increase in the differential between NYMEX WTI and the reference or regional index price used to price our oil and gas would reduce our cash flows from operations.

• Our estimated proved undeveloped reserves may not be ultimately developed or produced if their development is costlier or more time consuming than expected.

• Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline.

• Our undeveloped acreage must be drilled before lease expirations to hold the acreage by production, which could result in a substantial lease renewal cost or loss of our lease and prospective drilling opportunities.

• Funding through capital market transactions may be difficult and expensive due to our small public float, low market capitalization, and limited operating history.

• Covenants in our credit facility may restrict our business and financing activities and our ability to declare dividends.

• We may not be able to generate sufficient cash to service all of our indebtedness.

• Our derivative activities could result in financial losses or could reduce our earnings.

Risks Related to the Oil and Natural Gas Industry

•Drilling for and producing oil and natural gas are high risk activities.

•Conservation measures, alternative sources of energy and technological advances could reduce demand for oil, natural gas and NGLs.

•Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Risks Related to COVID-19, Acts of God, and Cyber Security

•Our business and operations may be adversely affected by the recent COVID-19 pandemic or other similar outbreaks.

•Power outages or limits and increased energy costs could have a material adverse effect on us.

•Extreme weather conditions could adversely affect our ability to conduct drilling activities.

•Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

PART II: OTHER INFORMATION

Risks Related to Legal, Regulatory, and Tax Matters

•Regulations related to environmental and occupational health and safety issues could adversely affect the cost, manner or feasibility of conducting our operations.

• We are responsible for the decommissioning, plugging, abandonment, and reclamation costs for our facilities.

• Increased regulation of our natural gas assets could cause our revenues to decline and operating expenses to increase.

• Regulatory initiatives relating to hydraulic fracturing, regulation of greenhouse gases, or protection of certain species of wildlife could result in increased costs and decreased production.

• New or increased taxes or fees on oil and natural gas extraction or production or changes in our effective tax rate, could adversely impact us.

Risks Related to Our Common Stock

•The market price of our common stock may be volatile, which could cause the value of your investment to decline.

•If we fail to continue to meet NYSE American listing requirements, our common stock could be delisted from trading, which would decrease the liquidity of our common stock and ability to raise additional capital.

•Our quarterly cash dividends, if any, may vary significantly both quarterly and annually.

•The board of directors may modify or revoke our dividend policy at any time at its discretion.

•Available cash for dividends depends primarily on our cash flow and not solely on our profitability, which may prevent us from paying dividends, even during periods in which we record net income.

•We have identified several material weaknesses in our internal control over financial reporting and may identify additional material weaknesses in the future, or otherwise fail to maintain an effective system of internal controls, which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations or fail to prevent fraud. As a result, stockholders could lose confidence in our financial and other public reporting, which would harm our business and the trading price of our common stock.

Risks Related to the Company

•Our business and operations could be adversely affected if we lose key personnel.

•Our executive officers, directors and principal stockholders have the ability to control or significantly influence all matters submitted to the Company’s stockholders for approval.

•Conflicts of interest could arise in the future between us, on the one hand, and certain of our stockholders and their respective affiliates.

Risks Related to Our Business, Operations, and Strategy

Oil, natural gas, and NGL prices are volatile. An extended decline in commodity prices may adversely affect our business, financial condition, or results of operations and our ability to meet our capital expenditure obligations and financial commitments. Additionally, the value of our reserves calculated using SEC pricing may be higher than the fair market value of our reserves calculated using current market prices.

The prices we receive for our oil, natural gas, and NGLs production heavily influence our revenue, profitability, access to capital, and future rate of growth. Oil, natural gas, and NGLs are commodities and, therefore, their prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the commodities market has been volatile. For example, during the period from January 1, 2015 to March 31, 2021, NYMEX West Texas Intermediate (referred to as WTI) oil prices ranged from a high of $77.41 per Bbl on June 27, 2018 to a low of $(36.98) per Bbl on April 20, 2020. During fiscal 2021, WTI prices ranged from a high of $66.08 to a low of $35.64 per Bbl. Average daily prices for NYMEX Henry Hub gas ranged from a high of $23.86 per MMBtu to a low of $1.41 per MMBtu during the same period. If the prices of oil and natural gas continue to be volatile, reverse their recent increases, or decline, our operations, financial condition, cash flows and level of expenditures may be materially and adversely affected. Moreover, the duration and magnitude of any decline in oil, natural gas or NGL prices cannot be predicted with accuracy, and this market will likely continue to be volatile in the future. The prices we receive for our production, and the levels of our production, depend on numerous factors beyond our control. These factors include the following:

•worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas, and NGLs;

•the price and quantity of foreign imports, including foreign oil;

•the actions by members of the Organization of the Petroleum Exporting Countries, or OPEC;

•political, economic, and military conditions in or affecting other producing countries, including embargoes or conflicts in the Middle East, Africa, South America and Russia;

PART II: OTHER INFORMATION

•the level of global oil and natural gas exploration and production activity;

•the level of global oil and natural gas inventories;

•prevailing prices on local price indices in the areas in which we operate;

•the cost of producing and delivering oil and natural gas and conducting other operations;

•the recovery rates of new oil, natural gas and NGL reserves;

•lead times associated with acquiring equipment and products, and availability of qualified personnel;

•late deliveries of supplies;

•technical difficulties or failures;

•the proximity, capacity, cost, and availability of gathering and transportation facilities;

•localized and global supply and demand fundamentals and transportation availability;

•localized and global weather conditions;

•public health concerns such as COVID-19;

•technological advances affecting energy consumption, including advances in exploration, development and production technologies;

•shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil, natural gas, and NGLs;

•uncertainty in capital and commodities markets and the ability of companies in our industry to raise equity capital and debt financing;

•the price and availability of alternative fuels; and

•domestic, local, and foreign governmental regulation and taxes.

Lower commodity prices will reduce our cash flows and borrowing ability. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically. We have historically been able to hedge our oil and natural gas production at prices that are significantly higher than current strip prices. However, in the current commodity price environment, our ability to enter into comparable derivative arrangements may be limited, and, in the future, we will not be under an obligation to hedge a specific portion of our oil or natural gas production.

Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits. While it is difficult to project future economic conditions and whether such conditions will result in impairment of proved property costs, we consider several variables including specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors. In addition, sustained periods with oil and natural gas prices at levels lower than current West Texas Intermediate strip prices and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone or eliminate our development drilling, which could result in the reduction of some of our proved undeveloped reserves and related standardized measure. If we are required to curtail our drilling program, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity, or ability to finance planned capital expenditures.

Our exploration and development projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the exploitation, development, and acquisition of oil and natural gas reserves. We expect to fund our growth primarily through cash flow from operations, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. A reduction in commodity prices from current levels may result in a decrease in our actual capital expenditures, which would negatively impact our ability to grow production.

PART II: OTHER INFORMATION

Our cash flow from operations and access to capital are subject to a number of variables, including:


•						our proved reserves;
•						the level of hydrocarbons we are able to produce from existing wells and the timing of such production;
•						the prices at which our production is sold;
•						operating costs and other expenses;
•						the availability of takeaway capacity;
•						our ability to acquire, locate and produce new reserves; and
•						our ability to borrow under our revolving credit facility.

If our revenues or the borrowing base under our revolving credit facility decreases as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves, or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations and growth at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under our revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties, which in turn could lead to a decline in our reserves and production, and would adversely affect our business, financial condition, and results of operations.

Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.

We have acquired significant amounts of unproved property in order to further our development efforts and expect to continue to undertake acquisitions in the future. Development and exploratory drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our results of operations over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our investments. Additionally, we cannot assure you that unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such unproved property or wells.

Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties that we acquire, or obtain protection from sellers against such liabilities.

Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs, and potential liabilities, including environmental liabilities. Such assessments are inexact and inherently uncertain. For these reasons, the properties we have acquired or will acquire in the future may not produce as projected or may be more costly to operate than projected. In connection with the assessments, we perform a review of the subject properties, but such a review will not reveal all existing or potential problems. In the course of our due diligence, we may not review every well, pipeline or associated facility. We cannot necessarily observe structural and environmental problems, such as pipe corrosion or groundwater contamination, when a review is performed. We may be unable to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.

Our identified drilling locations are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. In addition, we may not be able to raise the substantial amount of capital that would be necessary to drill such locations.

Our management team has specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These locations represent a significant part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including oil, natural gas, and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals, and other factors. Because of these uncertain factors, we do not know if the numerous potential well locations we have identified will ever be drilled or if we will be able to produce natural gas or oil from these or any other potential locations. In addition, unless production is established within the

PART II: OTHER INFORMATION

spacing units covering the undeveloped acres on which some of the potential locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

Our undeveloped leasehold acreage must be developed or the lease renewed prior to the time the leases for such acreage expire. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

In addition, we will require significant additional capital over a prolonged period in order to pursue the development of these locations, and we may not be able to raise or generate the capital required to do so. Any drilling activities we are able to conduct on these potential locations may not be successful or result in our ability to add additional proved reserves to our overall proved reserves or may result in a downward revision of our estimated proved reserves, which could have a material adverse effect on our future business and results of operations.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves.

In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil, natural gas and NGL prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.

Actual future production, oil, natural gas and NGL prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves. In addition, we may revise reserve estimates to reflect production history, results of exploration and development, existing commodity prices and other factors, many of which are beyond our control.

You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. For example, our estimated proved reserves as of September 30, 2020 ~~(the “2019 10-K”) which~~were calculated under SEC rules using the unweighted arithmetic average first-day-of-the-month prices for the prior 12 months of $43.63 per Bbl for oil and NGL volumes and $1.967 per MMBtu for natural gas volumes. Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits.

There is ~~incorporated by this reference.~~

~~Set forth below are certain material changes to the Risk Factors disclosed~~a limited amount of production data from horizontal wells completed in the ~~2019 10-K~~Permian Basin and its San Andres Formation. As a result, reserve estimates associated with horizontal wells in this area are subject to greater uncertainty than estimates associated with reserves attributable to vertical wells in the same area.

Reserve engineers rely in part on the production history of nearby wells in establishing reserve estimates for a particular well or field. Horizontal drilling in the San Andres Formation of the Permian Basin is a relatively recent development, whereas vertical drilling has been utilized by producers in this area for over 50 years. As a result, the amount of production data from horizontal wells available to reserve engineers is relatively small compared to that of production data from vertical wells. Until a greater number of horizontal wells have been completed in the San Andres Formation, and a longer production history from these wells has been established, there may be a greater variance in our proved reserves on a year-over-year basis due to the ~~Company executing~~transition from vertical to horizontal reserves in both the proved developed and proved undeveloped categories. We cannot assure you that any such variance would not be material and any such variance could have a material and adverse impact on our cash flows and results of operations.

PART II: OTHER INFORMATION

Part of our strategy involves drilling using the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.

Our operations involve utilizing the latest drilling and completion techniques as developed by us and our service providers. As of March 31, 2021, we have drilled and completed 69 gross operated horizontal wells on our Champions and New Mexico Assets, and therefore are subject to increased risks associated with horizontal drilling as compared to companies that have greater experience in horizontal drilling activities. Risks that we face while drilling include, but are not limited to, failing to land our wellbore in the desired drilling zone, not staying in the desired drilling zone while drilling horizontally through the formation, not running our casing the entire length of the wellbore and not being able to run tools and other equipment consistently through the horizontal wellbore. Risks that we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages, not being able to run tools the entire length of the wellbore during completion operations and not successfully cleaning out the wellbore after completion of the final fracture stimulation stage.

Additionally, certain ~~Agreement~~of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and ~~Plan~~the time required to drill and complete multiple wells before any such wells begin producing.

Ultimately, the success of ~~Merger (the “Merger Agreement”)~~these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficient time period. If our drilling results are less than anticipated or we are unable to execute our drilling program because of capital constraints, lease expirations, access to gathering systems, and/or commodity prices decline, the return on our investment in these areas may not be as attractive as we anticipate. Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future.

Approximately 47% of our net leasehold acreage is undeveloped and that acreage may not ultimately be developed or become commercially productive, which could cause us to lose rights under our leases as well as have a material adverse effect on our oil and natural gas reserves and future production and, therefore, our future cash flow and income.

Oil and natural gas leases generally must be drilled before the end of the lease term or the leaseholder will lose the lease and any capital invested therein. In addition, leases may also be lost due to legal issues relating to the ownership of leases. Any delays in drilling or legal issues causing us to lose leases on properties could have a material adverse effect on our results of operations and reserve growth.

As of March 31, 2021, approximately 47% of our net leasehold acreage was undeveloped or acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and natural gas regardless of whether such acreage contains proved reserves. Unless production is established on the undeveloped acreage covered by our leases, such leases will expire. Our future oil and natural gas reserves and production and, therefore, our future cash flow and income are highly dependent on successfully developing our undeveloped leasehold acreage.

Our drilling plans are subject to change based upon various factors, including factors that are beyond our control. Such factors include drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints, and regulatory approvals. If our leases expire, we will lose our right to develop such properties.

Substantially all of our producing properties are located in the Northwest Shelf within the Permian Basin of West Texas, making us vulnerable to risks associated with operating in one major geographic area. Specifically, as the Permian Basin is an area of high industry activity, we may be unable to hire, train, or retain qualified personnel needed to manage and operate our assets.

Substantially all of our producing properties are geographically concentrated in the Northwest Shelf sub-basin within the Permian Basin of West Texas, an area in which industry activity has increased rapidly. At September 30, 2020, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, a number of our properties could experience any of the same conditions at the same time and, when compared to other companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, water shortages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

PART II: OTHER INFORMATION

Specifically, demand for qualified personnel in this area, and the cost to attract and retain such personnel, may increase substantially in the future. Moreover, our competitors, including those operating in multiple basins, may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. Any delay or inability to secure the personnel necessary for us to continue or complete our current and planned development activities could have a negative effect on production volumes or significantly increase costs, which could have a material adverse effect on our results of operations, liquidity and financial condition.

In addition, the geographic concentration of our assets including our total estimated proved reserves as of September 30, 2020, exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

Our drilling and production programs may not be able to obtain access on commercially reasonable terms or otherwise to truck transportation, pipelines, gas gathering, transmission, storage and processing facilities to market our oil and gas production, certain of which we do not control, and our initiatives to expand our access to midstream and operational infrastructure may be unsuccessful.

The marketing of oil and natural gas production depends in large part on the capacity and availability of pipelines and storage facilities, trucks, gas gathering systems and other transportation, processing and refining facilities. Access to such facilities is, in many respects, beyond our control. If these facilities are unavailable to us on commercially reasonable terms or otherwise, we could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons. We rely (and expect to rely in the future) on facilities developed and owned by third parties in order to store, process, transmit, and sell our oil and gas production. Our plans to develop and sell our oil and gas reserves, the expected results of our drilling program and our cash flow and results of operations could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient facilities and services to us on commercially reasonable terms or otherwise. The amount of oil and gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. For example, increases in activity in the Permian Basin could contribute to bottlenecks in processing and transportation that may negatively affect our results of operations, and these adverse effects could be disproportionately severe to us compared to our more geographically diverse competitors.

Similarly, the concentration of our assets within a small number of producing formations exposes us to risks, such as changes in field-wide rules, which could adversely affect development activities or production relating to those formations. In addition, in areas where exploration and production activities are increasing, as has been the case in recent years in the Permian Basin, we are subject to increasing competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages or delays. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, we may be provided only limited, if any, notice as to when these circumstances will arise and their duration.

While we have undertaken initiatives to expand our access to midstream and operational infrastructure, these initiatives may be delayed or unsuccessful. As a result, our business, financial condition, and results of operations could be adversely affected.

The prices we receive for our production may be affected by local and regional factors.

The prices we receive for our production will be determined to a significant extent by factors affecting the local and regional supply of and demand for oil and natural gas, including the adequacy of the pipeline and processing infrastructure in the region to process and transport our production and that of other producers. Those factors result in basis differentials between the published indices generally used to establish the price received for regional oil and natural gas production and the actual price we receive for our production, which may be lower than index prices. If the price differentials pursuant to which our production is subject were to widen due to oversupply or other factors, our revenue could be negatively impacted.

An increase in the differential between NYMEX WTI and the reference or regional index price used to price our oil and gas would reduce our cash flows from operations.

Our oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive for our oil and gas are typically lower than the relevant benchmark prices, such as NYMEX WTI.

PART II: OTHER INFORMATION

The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing, such as pipeline capacity and processing infrastructure. Additionally, insufficient pipeline or transportation capacity, lack of demand in any given operating area or other factors may cause the differential to increase in a particular area compared with other producing areas. For example, production increases from competing Permian Basin producers, combined with limited pipeline and transportation capacity in the area, have gradually widened differentials in the Permian Basin.

For the three and six months ended March 31, 2021, ~~dated~~our realized crude oil differential to NYMEX WTI averaged $1.13 and $1.72 per Bbl of oil and our realized natural gas differential to NYMEX Henry Hub averaged ($4.82) and ($1.68) per Mcf of gas. Given that a significant amount of our production is from the Permian Basin, if the negative price differential in the Permian Basin increases, we expect that the effect of our price differential on our revenues will also increase. Increases in the differential between the benchmark prices for oil and gas, such as the NYMEX WTI and NYMEX Henry Hub, and the realized price we receive could significantly reduce our revenues and our cash flow from operations.

The development of our estimated proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated proved undeveloped reserves may not be ultimately developed or produced.

At September 30, 2020, approximately 47% of our total estimated proved reserves were classified as proved undeveloped. Our approximately 26,600.7 MBoe of estimated proved undeveloped reserves are estimated to require an estimated $129.4 million of development capital over the next five years. Our approximately 63,126.6 MBoe of estimated probable reserves are estimated to require $109.3 million of development capital over the next five years. Our approximately 13,006.3 MBoe of possible reserves are estimated to require $2.3 million of development capital over the next five years. Our development of these reserves may take longer and require higher levels of capital expenditures than we currently anticipate. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices, actual drilling results, the availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments. We expect to fund our growth primarily through cash flow from operations, availability under our revolving credit facility, and subsequent equity or debt offerings when appropriate. Delays in the development of our reserves, increases in costs to drill and develop such reserves, or decreases in commodity prices will reduce the PV-10 value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our proved undeveloped reserves as unproved reserves.

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

We own less than 100% of the working interest in the oil and gas leases on which we conduct operations, and other parties will own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. A partner may be unable or unwilling to pay its share of project costs, may be unable to access debt or equity financing, and, in some cases, may declare bankruptcy. In the event any of our project partners do not pay their share of such costs, we would likely have to pay those costs, and we may be unsuccessful in any efforts to recover these costs from our partners, which could materially adversely affect our financial position.

We own non-operating interests in properties developed and operated by third parties, and as a result, we are unable to control the operation and profitability of such properties.

We participate in the drilling and completion of wells with third-party operators that exercise exclusive control over such operations. As a participant, we rely on the third-party operators to successfully operate these properties pursuant to joint operating agreements and other similar contractual arrangements.

As a participant in these operations, we may not be able to maximize the value associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling and development activities on properties operated by third parties, which depend on a number of factors under the control of a third-party operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition,

PART II: OTHER INFORMATION

the third-party operator’s operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact the timing and potential success of drilling and development activities in a manner that we are unable to control. A third-party operator’s failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and have a material adverse effect on our financial condition and results of operations.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take write-downs of the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write down the carrying value of our properties. A write down constitutes a non-cash charge to earnings. If market or other economic conditions deteriorate or if oil, natural gas and NGL prices decline, we may incur impairment charges, which may have a material adverse effect on our results of operations.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploitation, development and exploration activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be adversely affected.

We depend upon several significant purchasers for the sale of most of our oil and natural gas production. The loss of one or more of these purchasers could, among other factors, limit our access to suitable markets for the oil, natural gas and NGLs we produce.

The availability of a ready market for any oil, natural gas and NGLs we produce depends on numerous factors beyond the control of our management, including but not limited to the extent of domestic production and imports of oil, the proximity and capacity of pipelines, the availability of skilled labor, materials and equipment, the effect of state and federal regulation of oil and natural gas production and federal regulation of oil and gas sold in interstate commerce. In addition, we depend upon several significant purchasers for the sale of most of our oil and natural gas production. We cannot assure you that we will continue to have ready access to suitable markets for our future oil and natural gas production.

We have exposure to credit risk through receivables from purchasers of our oil, natural gas and NGL production. Stakeholder Crude Oil Marketing, LLC and Stakeholder Midstream, LLC (collectively “Stakeholder”) accounted for 87% of our revenues for the six months ended March 31, 2021. This concentration of purchasers may impact our overall credit risk in that these entities may be similarly affected by changes in economic conditions or commodity price fluctuations. We do not require our customers to post collateral. The inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation may materially adversely affect our financial condition and results of operations.

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

Our operations are subject to inherent risks, some of which are beyond our control. We are not insured against all risks. Losses and liabilities arising from uninsured and under insured events could materially and adversely affect our business, financial condition or results of operations.

PART II: OTHER INFORMATION

Our exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the risk of fire, explosions, blowouts, surface cratering or other cratering, uncontrollable flows of natural gas, oil, well fluids and formation water, pipe or pipeline failures, abnormally pressured formations, casing collapses, reservoir damage and environmental hazards such as oil, produced water or chemical spills, natural gas leaks, ruptures or discharges of toxic gases.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

•

injury or loss of life;

•

employee/employer liabilities and risks, including wrongful termination, discrimination, labor organizing, retaliation claims, and general human resource related matters;

•

damage to and destruction of property, natural resources and equipment;

•

pollution and other environmental hazards or damage;

•

abnormally pressured formations, fires or explosions or natural disasters;

•

mechanical difficulties, such as stuck oil field drilling and service tools and casing collapse;

•

regulatory investigations and penalties;

•

landowner claims for property damage and restoration costs;

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suspension of our operations; and repair and remediation costs.

•

repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. Claims for loss of oil and natural gas production and damage to formations can occur in our industry. Litigation arising from a catastrophic occurrence at a location where our systems are deployed may result in our being named as a defendant in lawsuits asserting large claims.

Moreover, insurance may not be available in the future at commercially reasonable costs and on commercially reasonable terms. Also, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not covered or fully covered by insurance and any delay in the payment of insurance proceeds for covered events could have a material adverse effect on our business, financial condition and results of operations.

Properties that we decide to drill may not yield oil, natural gas or NGLs in commercially viable quantities.

Our prospects are in various stages of evaluation, ranging from prospects that are currently being drilled, to prospects that will require substantial additional seismic data processing and interpretation. Properties that we decide to drill that do not yield oil, natural gas or NGLs in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects. Further, our drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:


•						unexpected drilling conditions;
•						title problems;
•						pressure or lost circulation in formations;
•						equipment failure or accidents;
•						adverse weather conditions;
•						compliance with environmental and other governmental or contractual requirements; and
•						increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

PART II: OTHER INFORMATION

We may be unable to make accretive acquisitions or successfully integrate acquired businesses or assets, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future we may make acquisitions of oil and gas properties or businesses that complement or expand our current business. The successful acquisition of oil and gas properties requires an assessment of several factors, including:

•recoverable reserves;

•future oil, natural gas and NGL prices and their applicable differentials;

•estimates of operating costs;

•estimates future development costs;

•estimates of the costs and timing of plugging and abandonment; and

•environmental and other liabilities.

The accuracy of these assessments is inherently uncertain, and we may not be able to identify accretive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and capabilities. Reviews may not always be performed on every well, and environmental problems, such as subsurface or groundwater contamination, are not necessarily observable even when a review is performed. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even if we do identify accretive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms.

The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations.

In addition, our revolving credit facility imposes certain limitations on our ability to enter into mergers or combination transactions as well as limits our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions.

We may incur losses as a result of title defects in the properties in which we invest.

It is our practice in acquiring oil and natural gas leases or interests not to incur the expense of retaining lawyers to examine the title to the mineral interest at the time of acquisition. Rather, we rely upon the judgment of lease brokers or land men who perform the fieldwork in examining records in the appropriate governmental office before attempting to acquire a lease in a specific mineral interest. The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we do typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.

Our operations could be impacted by burdens and encumbrances on title to our properties.

Our leasehold and other acreage may be subject to existing oil and natural gas leases, liens for current taxes and other burdens, including other mineral encumbrances and restrictions customary in the oil and natural gas industry. Such liens and burdens could materially interfere with the use or otherwise affect the value of such properties. Additionally, any cloud on the title of the working interests, leases and other rights owned by us could have a material adverse effect on our operations.

PART II: OTHER INFORMATION

Our undeveloped acreage must be drilled before lease expirations to hold the acreage by production. In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.

Unless production is established within the spacing units covering the undeveloped acres on which some of our drilling locations are identified, our leases for such acreage will expire. As of March 31, 2021, 79% of our net undeveloped acreage was set to expire in fiscal year 2021. We intend to extend or renew every material lease that is set to expire in fiscal year 2021 to the extent possible and expect to incur $1 million to extend or renew every material lease that is set to expire in fiscal year 2021, without taking into account the drilling of PUDs and holding leases by production. Where we do not have the option to extend a lease, however, we may not be successful in negotiating extensions or renewals. Our ability to drill and develop our acreage and establish production to maintain our leases depends on a number of uncertainties, including oil, natural gas and NGL prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. The cost to renew such leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all. As such, our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. These risks are greater at times and in areas where the pace of our exploration and development activity slows.

Our use of 2-D and 3-D seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.

Even when properly used and interpreted, 2-D and 3-D seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. In addition, the use of 3-D seismic and other advanced technologies requires greater predrilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures. As a result, our drilling activities may not be successful or economical.

Acquisitions of assets or businesses may reduce, rather than increase, our distributable cash flow or may disrupt our business.

Even if we make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in our cash flow. Any acquisition involves potential risks that may disrupt our business, including the following, among other things:


•			mistaken assumptions about volumes or the timing of those volumes, revenues or costs, including synergies;
•			an inability to successfully integrate the acquired assets or businesses;
•			the assumption of unknown liabilities;
•			exposure to potential lawsuits;
•			limitations on rights to indemnity from the seller;
•			the diversion of management’s and employees’ attention from other business concerns;
•			unforeseen difficulties operating in new geographic areas; and
•			customer or key employee losses at the acquired businesses.

We may need to access funding through capital market transactions. Due to our small public float, low market capitalization, and limited operating history, it may be difficult and expensive for us to raise additional funds.

We may need to raise funds through the issuance of shares of our common stock or securities linked to our common stock. Our ability to raise these funds may be dependent on a number of factors, including the risk factors further described herein and the low trading volume and volatile trading price of our shares of common stock. The stocks of small cap companies tend to be highly volatile. We expect that the price of our common stock will be highly volatile for the next several years.

As a result, we may be unable to access funding through sales of our common stock or other equity-linked securities. Even if we were able to access funding, the cost of capital may be substantial due to our low market cap and small public float. The terms of any funding we are able to obtain may not be favorable to us and may be highly dilutive to our stockholders. We may be unable to access capital due to unfavorable market conditions or other market factors outside of our control. There can be no assurance that we will be able to raise additional capital when needed. The failure to obtain additional capital when needed would have a material adverse effect on our business.

PART II: OTHER INFORMATION

Our credit facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to declare dividends.

The operating and financial restrictions and covenants in our credit facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage, expand or pursue our business activities or pay dividends. Our credit facility restricts, and any future financing agreements likely will restrict, its ability to, among other things:


•			incur indebtedness;
•			issue certain equity securities, including preferred equity securities;
•			incur certain liens or permit them to exist;
•			engage in certain fundamental changes, including mergers or consolidations;
•			make certain investments, loans, advances, guarantees and acquisitions;
•			sell or transfer assets;
•			enter into sale and leaseback transactions;
•			redeem or repurchase shares from our stockholders;
•			pay dividends to our stockholders unless the net leverage ratio does not exceed 2.75 to 1.0, the total revolving credit exposures under our credit facility are not greater than 80% of the total revolving commitments, and no default or event of default then exists or would exist upon the payment of the dividend;
•			make certain payments of junior indebtedness;
•			enter into certain types of transactions with our affiliates;
•			enter into certain restrictive agreements; and
•			enter into swap agreements and hedging arrangements.

Our ability to comply with these restrictions and covenants in the future is uncertain and will be affected by the levels of free cash flow and events or circumstances beyond our control, such as a downturn in our business or the economy in general or reduced oil, natural gas and NGL prices. A failure to comply with the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. Further, our ability to pay dividends to our stockholders will be restricted and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments, and our common stock holders could experience a partial or total loss of their investment. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders can seek to foreclose on our assets.

Our indebtedness could reduce our financial flexibility.

We have a revolving line of credit in place for borrowings and letters of credit with Truist Bank, successor by merger to SunTrust Bank, as administrative agent and issuing lender, and the lenders named therein, which provides for a revolving credit facility of up to $500.0 million (subject to an applicable borrowing base). As of March 31, 2021, we had $97.5 million of outstanding borrowings and an additional $37.5 million available under our revolving credit facility and were in compliance with all applicable financial covenants thereunder. On October 21, 2020, byREP LLC entered into the Seventh Amendment and ~~among,~~Consent to its credit facility to incorporate the ~~Company, Antman Sub,~~changes in the legal structure of REP LLC ~~a newly-formed Delaware limited liability company and wholly-owned subsidiary~~upon consummation of the Merger, including the joinder of the Company (“as the parent guarantor thereto. The Seventh Amendment was effective upon closing of the Merger. Effective March 5, 2021, the Company and REP LLC entered into the Eighth Amendment to the credit facility pursuant to which the parties thereto and reaffirmed the borrowing base at $135 million with total commitments increasing to $135 million and extended the maturity date of the facility by an additional two years. The Company elected not to solicit additional lender commitments at this time as management believes it currently has sufficient liquidity to meet its future requirements. However, the Company reserves the option under its revolving credit facility, subject to lender approval, to request an increase in the lender commitments from time to time up to the amount of the borrowing base then in effect.

PART II: OTHER INFORMATION

The level of our indebtedness could affect our operations in several ways, including the following:


			•						a significant portion of our cash flow could be used to service the indebtedness;
			•						a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
			•						the covenants contained in our revolving credit facility limit our ability to borrow additional funds, dispose of assets, pay dividends and make certain investments; and
			•						a high level of debt could impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate purposes, or other purposes.

Any significant reduction in our borrowing base under our revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our revolving credit facility limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine in accordance with the terms of the agreement. The borrowing base depends on, among other things, projected revenues from, and asset values of, the proved oil and natural gas properties securing our loan. The value of our proved reserves is dependent upon, among other things, the prevailing and expected market prices of the underlying commodities in our estimated reserves. A further reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations, and our ability to meet our capital expenditure obligations and financial commitments. Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. We could be forced to repay a portion of our bank borrowings or transfer to the lenders additional collateral due to redeterminations of our borrowing base that result in a reduction of the available revolving commitments. If we are forced to do so, we may not have sufficient funds to make such repayments or provide such collateral. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings, provide additional collateral or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

In the future, we may not be able to access adequate funding under our revolving credit facility as a result of a decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a redetermination and reduction of the borrowing base in the future and, in such a case, we could be required to repay any indebtedness in excess of the reduced borrowing base. As a result, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt arrangements, which may not be successful.

Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital, or restructure or refinance indebtedness. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of our existing revolving credit facility or future debt arrangements may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. Our revolving credit facility currently restricts our ability to dispose of assets and our use of the proceeds from such dispositions. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.

PART II: OTHER INFORMATION

Our derivative activities could result in financial losses or could reduce our earnings.

To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in the prices of oil, natural gas, and NGLs, we enter or may enter into commodity derivative contracts for a significant portion of our production, primarily consisting of swaps, put options and call options. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.

Derivative instruments also can expose us to the risk of financial loss in some circumstances, including when:


•						production is less than the volume covered by the derivative instruments;
•						the counterparty to the derivative instrument defaults on its contractual obligations;
•						there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
•						there are issues with regard to legal enforceability of such instruments.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile oil, natural gas, and NGL prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil, natural gas, and NGLs, which could also have an adverse effect on our financial condition.

Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the contract and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

During periods of declining commodity prices, our derivative contract receivable positions could generally increase, which increases our counterparty credit exposure. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss with respect to our commodity derivative contracts.

Risks Related to Our Merger ~~Sub”), and~~Transaction with Riley Exploration – Permian, LLC ~~a Delaware limited liability company (“Riley”), pursuant to which Merger Sub will be merged with and into Riley,~~

Combining our business with Riley ~~surviving that merger as a wholly-owned subsidiary~~Exploration – Permian, LLC may be more difficult, costly or time-consuming than expected and we may fail to realize the anticipated benefits of the ~~Company~~Merger, which may adversely affect our business results and negatively affect the value of our common stock.

Our merger transaction (the ~~“Merger”) (for more information regarding~~Merger) with Riley Exploration – Permian, LLC (REP, LLC) involved the ~~Merger, See Part II, Item 5, Other Information):~~

~~The exchange ratio is not adjustable based on the market price~~combination of ~~the Company’s common stock, so the merger consideration at closing may have a greater or lesser value than the market price at the time the Merger Agreement was signed.~~

The Merger Agreement has set the exchange ratio formula for Riley common units, and the exchange ratio is adjustable upward or downward if the number of outstanding Riley units or shares of the Company’s stock shall change including by reason of any reclassification, recapitalization, stock split (including a reverse stock split), or combination, exchange, readjustment of shares, or similar transaction, or any stock dividend or distribution paid in stock (other than certain specified changes in the Merger Agreement). Any changes in the market price of the Company’s common stock beforetwo companies which, until the completion of the Merger, ~~will not affect the number of shares of the Company’s common stock that Riley members will be entitled to receive pursuant to the Merger Agreement. Therefore, if before the completion~~operated as independent companies. The success of the Merger will depend on, among other things, the ~~market price~~ability of our two companies to combine our businesses in a manner that adds value to shareholders. However, there can be no assurances that our respective businesses can be integrated successfully, and we will be required to devote significant management attention and resources to the ~~Company’s common stock declines from~~integration process. We must achieve the ~~market price on~~anticipated improvement in free cash flow generation and returns and achieve the ~~date of~~planned cost savings without adversely affecting current revenues or compromising the Merger Agreement, then Riley members could receive merger consideration with substantially lower value. Similarly, if before the completion of the Merger, the market price of the Company’s common stock increases from the market price on the date of the Merger Agreement, then Riley members could receive merger consideration with substantially moredisciplined investment philosophy to maximize value for ~~their Riley common units than~~shareholders.

There are a large number of processes, policies, procedures, operations and technologies, and systems that must be integrated, and although we expect that the ~~parties had foreseen in the establishment~~elimination of ~~the exchange ratio.~~

~~The Merger may not be completed~~duplicative costs, strategic benefits, and ~~the Merger Agreement may be terminated in accordance with its terms. Failure to complete the Merger could negatively impact the price of shares of the Company’s common stock~~additional income, as well as the ~~Company’s future business and financial results.~~

~~Table~~realization of ~~Contents~~

~~The Merger is subject to a number of conditions that must be satisfied prior~~other efficiencies related to the ~~completion~~integration of the ~~Merger. These conditions~~business, may offset incremental transaction and Merger-related costs over time, we may encounter difficulties in the integration and any net benefit may not be achieved in the near term or at all. It is possible that the integration process could take longer than originally anticipated and could result in the loss of key employees; the loss of commercial and vendor partners; the disruption of our ongoing businesses; inconsistencies in standards, controls, procedures and policies; unexpected integration issues; and higher than expected integration costs.

An inability to realize the ~~completion~~full extent of the anticipated benefits of the Merger ~~some of which are beyond~~and the control of the Company and Riley, may not be satisfied (or, where permitted, waived) in a timely manner or at all, and, accordingly, the Merger may be delayed or may not be completed. The Merger Agreement may also be terminated under certain circumstances. If theother transactions contemplated by the Merger Agreement, ~~are not completed for~~as well as any ~~reason, the Company’s ongoing business and financial results may be adversely affected.~~

The Company’s stockholders will have a reduced ownership and voting interest in, and will exercise less influence over the management of, the combined company following the completion of the Merger as compared to their current ownership and voting interestsdelay encountered in the ~~Company.~~integration process, could have an adverse effect upon the

PART II: OTHER INFORMATION

~~After the completion~~revenues, level of the Merger, the Company’s current stockholders will own a smaller percentage of the combined company than their ownership of the Company prior to the Merger. As of the date the Merger Agreement was executed, it was estimated that as a result of the Mergerexpenses and based solely on the exchange ratio of 97.796467, current Riley members would own, or hold rights to acquire, in the aggregate approximately 95% of the fully diluted closing common stock of the Company and current stockholders of the Company would own in the aggregate approximately 5% of the fully diluted closing common stock of the Company.

During the pendency of the Merger, the Company may not be able to enter into a business combination with another party at a favorable price because of restrictions in the Merger Agreement, which could adversely affect its business.

Covenants in the Merger Agreement impede the ability of the Company to make acquisitions, subject to certain exceptions relating to fiduciary duties, or to complete other transactions that are not in the ordinary course of business pending completion of the Merger. As a result, if the Merger is not completed, the Company may be at a disadvantage to its competitors during that period. In addition, while the Merger Agreement is in effect, the Company is generally prohibited from soliciting, initiating, encouraging or entering into certain extraordinary transactions, such as a merger, sale of assets or other business combination outside the ordinary course of business with any third party, subject to certain exceptions relating to fiduciary duties.

Investigations regarding the Merger could result in one or more lawsuits against the Company’s board of directors and/or the Company, and other lawsuits may be filed against the Company, Riley and/or their respective boards challenging the Merger. An adverse ruling in any such lawsuit may prevent the Merger from being completed.

Following the public announcement of the Merger, at least one investigation was launched by a law firm as to whether the Company’s board of directors acted in the best interest of the Company’s stockholders in agreeing to the Merger, whether the board was fully informed as to the valuation of the acquisition, whether the transaction is fair to the Company’s stockholders, and whether all information regarding the sales process undertaken by the Company’s board of directors and financial analyses supporting the transaction will be fully and fairly disclosed to the Company’s stockholders. While no litigation has been filed to date, there is a possibility that such investigations could result in a lawsuit against the Company, Riley, and/or their respective boards. Any such lawsuit could seek, among other things, injunctive relief or other equitable relief, including a request to rescind parts of the Merger Agreement already implemented and to otherwise enjoin the parties from consummating the Merger, in addition to other fees and costs.

~~Uncertainties associated with the Merger may cause a loss of management personnel and other key employees,~~operating results of the Company, which may adversely affect the value of our common stock.

Risks Related to the Oil and Natural Gas Industry

Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect ~~the~~our business, financial condition or results of operations.

Our future ~~business~~financial condition and results of operations ~~of the combined company.~~

~~Whether or not the Merger is completed, the announcement and pendency of the Merger could disrupt the businesses of the Company. The Company is dependent~~will depend on the ~~experience~~success of our exploitation, development, and ~~industry knowledge of its management~~acquisition activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and ~~other key employees~~natural gas production.

Our decisions to ~~execute its business plans. The surviving company’s success after the Merger~~purchase, explore, develop, or otherwise exploit prospects or properties will depend in part ~~upon~~on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.” In addition, our cost of drilling, completing, and operating wells is often uncertain before drilling commences.

Further, many factors may curtail, delay, or cancel our scheduled drilling projects, including the following:

•delays imposed by or resulting from compliance with environmental and other regulatory requirements including limitations on or resulting from wastewater discharge and disposal, subsurface injections, greenhouse gas emissions, and hydraulic fracturing;

•pressure or irregularities in geological formations;

•increases in the cost of, or shortages or delays in availability of drilling rigs and qualified personnel for hydraulic fracturing activities;

•shortages of or delays in obtaining water resources, suitable proppant, and chemicals in sufficient quantities for use in hydraulic fracturing activities;

•equipment failures or accidents;

•lack of available gathering facilities or delays in construction of gathering facilities;

•lack of available capacity on interconnecting transmission pipelines;

•adverse weather conditions, such as tornadoes, droughts, and ice storms;

•lack of available treatment or disposal options for oil and gas waste, including produced water;

•environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

•issues related to permitting under and compliance with environmental and other governmental regulations;

•declines or volatility in oil, natural gas, and NGL prices;

•limited availability of financing at acceptable terms;

•title problems or legal disputes regarding leasehold rights; and

•limitations in the market for oil, natural gas, and NGLs.

Conservation measures and technological advances could reduce demand for oil, natural gas and NGLs.

Our industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. Fuel and other energy conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil, natural gas and NGLs, technological advances in fuel economy and energy generation devices could reduce demand for oil, natural gas and NGLs. As competitors and others use or develop new technologies or technologies comparable to ours in the future, we may lose market share or be placed at a competitive disadvantage. Further, we may face competitive pressure to implement or acquire certain new technologies at a substantial cost. Some of our competitors may have greater financial, technical and personnel resources than we do, which may allow them to gain technological advantages or implement new technologies before we can. Additionally, we may be unable to implement new technologies or services at all, on a timely basis or at an acceptable cost. Limits on our ability to effectively use, implement or adapt to new technologies may have a material adverse effect on our business, financial condition and results of operations. Similarly, the impact of the ~~Company to retain key management~~changing demand for oil and gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and ~~other key employees in advance of the Merger, and of the combined company’s~~oilfield services could adversely affect our ability to doexecute our exploration and development plans within our budget and on a timely basis.

PART II: OTHER INFORMATION

We are highly dependent upon third-party services. The cost of oilfield services typically fluctuates based on demand for those services. There is no assurance that we will be able to contract for such services on a timely basis or that the cost of such services will remain at a satisfactory or affordable level. The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil, natural gas and NGL prices, causing periodic shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. We cannot predict whether these conditions will exist in the future and, if so, ~~following the Merger. Current employees~~what their timing and duration will be. Such shortages could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of ~~the Company may experience uncertainty about their roles within the combined company following the Merger, which~~operations.

Limitation or restrictions on our ability to obtain water may have an adverse effect on our operating results.

Water is an essential component of shale and conventional oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of flowback and produced water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties and market oil or natural gas.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, and raising additional capital, which could have a material adverse effect on our business.

Declining general economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit, the worldwide COVID-19 pandemic and the United States financial market have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. These factors, combined with volatile commodity prices, declining business and consumer confidence and increased unemployment, have precipitated an economic slowdown and a recession. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

We may not be able to keep pace with technological developments in our industry.

The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. In addition, other oil and natural gas companies may have greater financial, technical and personnel resources that allow them to enjoy technological advantages and that may in the ~~Company~~future allow them to ~~retain key~~implement new technologies before we can. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

PART II: OTHER INFORMATION

Negative public perception regarding us and/or our industry could have an adverse effect on our operations.

Negative public perception regarding us and/or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, oil spills, seismic activity, greenhouse gas emissions, and explosions of natural gas transmission lines may lead to increased regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

Risks Related to COVID-19, Acts of God, and Cyber Security

Our business and operations may be adversely affected by the recent COVID-19 pandemic or other similar outbreaks.

As a result of the COVID-19 outbreak that 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.

The timeline and potential magnitude of the COVID-19 outbreak is currently unknown. The continuation or amplification of this virus could continue to more broadly affect the United States and global economy, including our business and operations, and the demand for oil and gas. For example, a significant outbreak of coronavirus or other contagious diseases in the human population could result in a widespread health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that could affect our operating results. In addition, the effects of COVID-19 and concerns regarding its global spread have recently negatively impacted the domestic and international demand for crude oil and natural gas, which has contributed to price volatility. As the potential impact from COVID-19 is difficult to predict, the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. Any impact will depend on future developments and new information that may emerge regarding the severity and duration of COVID-19 and the actions taken by authorities to contain it or treat its impact, all of which will be beyond our control. These potential impacts, while uncertain, could adversely affect our results of operations.

Power outages, limited availability of electrical resources, and increased energy costs could have a material adverse effect on us.

Our operations are subject to electrical power outages, regional competition for available power, and increased energy costs. Power outages, which may last beyond our backup and alternative power arrangements, would harm our operations and our business.

We also may be subject to risks and unanticipated costs associated with obtaining power from various utility companies. Such utilities may be dependent on, and sensitive to price increases for, a particular type of fuel, such as coal, oil or natural gas. The price of these fuels and the electricity generated from them could increase as a result of proposed legislative measures related to climate change or efforts to regulate carbon or other greenhouse gas emissions.

Extreme weather conditions could adversely affect our ability to conduct drilling activities in the areas where we operate.

Our exploration, exploitation and development activities and equipment could be adversely affected by extreme weather conditions, such as floods, lightening, drought, ice and other storms, and tornadoes, which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment. Such extreme weather conditions could also impact other areas of our operations, including access to our drilling and production facilities for routine operations, maintenance and repairs and the availability of, and our access to, necessary third-party services, such as electrical power, water, gathering, processing, compression and transportation services. These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition and results of operations.

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Our business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.

The oil and natural gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations. For example, the industry depends on digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber incidents, including deliberate attacks or unintentional events, have increased. As an oil and natural gas producer, our technologies, systems, networks, and those of our business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, misuse, loss or destruction of proprietary and other information, or other disruption of business operations that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. We face various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected our operations to increased risks that could have a material adverse effect on our business. In particular, our implementation of various procedures and controls to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could lead to financial losses from remedial actions, loss of business or potential liability.

Loss of our information and computer systems could adversely affect our business.

We are dependent on our information systems and computer-based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

Risks Related to Legal, Regulatory, and Tax Matters

We are subject to stringent federal, state and local laws and regulations related to environmental and occupational health and safety issues that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.

Our operations are subject to stringent federal, state and local laws and regulations governing occupational safety and health aspects of our operations, the discharge of materials into the environment and environmental and human health protection. These laws and regulations may impose numerous obligations applicable to our operations including (i) the acquisition of a permit before conducting drilling, production, and other regulated activities; (ii) the restriction of types, quantities and concentration of materials that may be released into the environment; (iii) the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, protected species habitat, and other protected areas; (iv) the application of specific health and safety criteria addressing worker protection; (v) the imposition of substantial liabilities for pollution resulting from our operations; (vi) the installation of costly emission monitoring and/or pollution control equipment; and (vii) the reporting of the types and quantities of various substances that are generated, stored, processed, or released in connection with our properties. Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or EPA, the U.S. Fish and Wildlife Service, and analogous state agencies, and state oil and natural gas commissions, such as the Railroad Commission of Texas, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining or be unable to obtain required permits, which may delay or interrupt our operations or specific projects and limit our growth and revenue.

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There is inherent risk of incurring significant environmental costs and liabilities in the performance of our operations due to our handling of petroleum hydrocarbons and other hazardous substances and wastes, as a result of air emissions and wastewater discharges related to our operations, and because of historical operations and waste disposal practices at our leased and owned properties. Spills or other releases of regulated substances, including such spills and releases that occur in the future, could expose us to material losses, expenditures and liabilities under applicable environmental laws and regulations. Under certain of such laws and regulations, we could be subject to strict, joint and several liability for the removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination and even if our operations met previous standards in the industry at the time they were conducted. We may not be able to recover some or any of these costs from insurance. Changes in environmental laws and regulations occur frequently and tend to become more stringent over time, and any changes that result in more stringent or costly well drilling, construction, completion or water management activities, air emissions control or waste handling, storage, transport, disposal or cleanup requirements could require us to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position or financial condition. For example, on October 1, 2015, the EPA issued a final rule under the Clean Air Act, lowering the National Ambient Air Quality Standard, or NAAQS, for ground-level ozone from the current standard of 75 parts per billion, or ppb, for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. Subsequently, the EPA designated over 200 counties across the U.S. as “nonattainment” for these standards, meaning that new and modified stationary emissions sources in these areas are subject to more stringent permitting and pollution control requirements. If our operations become subject to these more stringent standards, compliance with these and other environmental regulations could delay or prohibit our ability to obtain permits for operations or require us to install additional pollution control equipment, the costs of which could be significant.

We are subject to complex laws that can affect the cost, manner or feasibility of doing business.

Exploration, development, production and sale of oil and natural gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with governmental regulations. Matters subject to regulation include:


•						permits for drilling operations;
•						drilling bonds;
•						reports concerning operations;
•						the spacing of wells;
•						the rates of production;
•						the plugging and abandoning of wells;
•						unitization and pooling of properties; and
•						taxation.

Under these laws, we could be liable for property damage and other damages. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties. Moreover, these laws could change in ways that substantially increase our costs. Any such liabilities, penalties, suspensions, terminations or regulatory changes could materially adversely affect our financial condition and results of operations.

We are responsible for the decommissioning, plugging, abandonment, and reclamation costs for our facilities.

We are responsible for compliance with all applicable laws and regulations regarding the decommissioning, plugging, abandonment, and reclamation of our facilities at the end of their economic life, the costs of which may be substantial. It is not possible to predict these costs with certainty since they will be a function of regulatory requirements at the time of decommissioning, plugging, abandonment, and reclamation. We may, in the future, determine it prudent or be required by applicable laws or regulations to establish and fund one or more decommissioning, plugging, abandonment, and reclamation reserve funds to provide for payment of future decommissioning, plugging, abandonment, and reclamation costs, which could decrease funds available to service debt obligations. In addition, such reserves, if established, may not be sufficient to satisfy such future decommissioning, plugging, abandonment, and reclamation costs and we will be responsible for the payment of the balance of such costs.

PART II: OTHER INFORMATION

SEC rules could limit our ability to book additional proved undeveloped reserves in the future.

SEC rules require that, subject to limited exceptions, proved undeveloped reserves, or PUDs, may only be booked if they relate to wells scheduled to be drilled within five years after the date of booking. This requirement has limited and may continue to limit our ability to book additional PUDs as we pursue our drilling program. Moreover, we may be required to write down our PUDs if we do not drill or plan on delaying those wells within the required five-year timeframe.

Should we fail to comply with all applicable regulatory agency administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, the Federal Energy Regulatory Commission (“FERC”) has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including civil penalty authority under the Natural Gas Act of 1938 (the “NGA”) to impose penalties for current violations of up to $1.0 million/d for each violation. FERC may also impose administrative and criminal remedies and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional facilities to FERC annual reporting requirements. We also must comply with the anti-market manipulation rules enforced by FERC. Additional rules and regulations pertaining to those and other matters may be considered or adopted by FERC from time to time. Additionally, the Federal Trade Commission (the “FTC”) has regulations intended to prohibit market manipulation in the petroleum industry with authority to fine violators of the regulations civil penalties of up to $1.0 million per day, and the Commodity Futures Trading Commission (the “CFTC”), prohibits market manipulation in the markets regulated by the CFTC, including similar anti-manipulation authority with respect to oil swaps and futures contracts as that granted to the CFTC with respect to oil purchases and sales. The CFTC rules subject violators to a civil penalty of up to the greater of $1.0 million or triple the monetary gain to the person for each violation. Failure to comply with those regulations in the future could subject us to civil penalty liability, as described in “Business—Regulation of the Oil and Gas Industry.”

A change in the jurisdictional characterization of our natural gas assets by federal, state or local regulatory agencies or a change in policy by those agencies may result in increased regulation of our natural gas assets, which may cause our revenues to decline and operating expenses to increase.

Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We believe that our natural gas gathering pipelines meet the traditional test that FERC has used to determine whether a pipeline is a gathering pipeline and is, therefore, not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and gathering services not subject to the jurisdiction of FERC, however, has been the subject of substantial litigation, and FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by FERC, the courts or Congress. If FERC were to consider the status of an individual facility and determine that the facility or services provided by it are not exempt from FERC regulation under the NGA and that the facility provides interstate service, the rates for, and terms and conditions of, services provided by such facility would be subject to regulation by FERC under the NGA or the Natural Gas Policy Act (“NGPA”).

Such regulation could decrease revenue and increase operating costs. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the NGA or NGPA, this could result in the imposition of substantial civil penalties, as well as a requirement to disgorge revenues collected for such services in excess of the maximum rates established by FERC.

FERC regulation may indirectly impact gathering services not directly subject to FERC regulation. FERC’s policies and practices across the range of its natural gas regulatory activities, including, for example, its policies on interstate open access transportation, ratemaking, capacity release, and market center promotion may indirectly affect intrastate markets. In recent years, FERC has pursued procompetitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue to pursue this approach as it considers matters such as pipeline rates and rules and policies that may indirectly affect the natural gas gathering services.

Natural gas gathering may receive greater regulatory scrutiny at the state level; therefore, our natural gas gathering operations could be adversely affected should they become subject to the application of state regulation of rates and services. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and complaint-based rate regulation. Our gathering operations could

PART II: OTHER INFORMATION

also be subject to safety and operational regulations relating to the design, construction, testing, operation, replacement and maintenance of gathering facilities.

We may be involved in legal proceedings that could result in substantial liabilities.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other ~~key~~ personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liability, penalties or sanctions may be insufficient. Judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the ~~ability~~next, and such changes could be material.

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the ~~combined company to do so following~~process.

For example, in February 2014, the ~~Merger.~~

~~The issuance of shares of the Company’s common stock to Riley members in the Merger will dilute substantially the voting power of the Company’s current stockholders.~~

~~If the Merger is completed, each outstanding common unit of Riley will be converted into the right to receive a number of shares of the Company’s common stock equal to the exchange ratio determined~~EPA asserted regulatory authority pursuant to the ~~Merger Agreement. Immediately following~~U.S. Safe Drinking Water Act’s (“SDWA”) Underground Injection Control (“UIC”) program over hydraulic fracturing activities involving the ~~Merger,~~use of diesel and issued guidance covering such activities. Also, beginning in 2012, the ~~Company’s stockholders are expected~~EPA issued a series of regulations under the federal Clean Air Act (“CAA”) that include New Source Performance Standards (“NSPS”), known as Subpart OOOO, for completions of hydraulically fractured natural gas wells and certain other plants and equipment and, in May 2016, published a final rule establishing new emissions standards, known as Subpart OOOOa, for methane and volatile organic compounds (“VOCs”) from certain new, modified and reconstructed equipment and processes in the oil and natural gas source category. The NSPS Subpart OOOO and OOOOa rules have since been subject to ~~own approximately 5%~~numerous legal challenges as well as EPA reconsideration proceedings and subsequent amendment proposals. Most recently, on September 14 and 15, 2020, EPA published two new rules in the Federal Register that remove the transmission and storage sectors of the ~~outstanding capital stock~~oil and gas industry from regulation under the NSPS and rescind methane-specific standards for the production and processing segments of the ~~combined company on a fully diluted basis,~~industry. However, states and ~~Riley’s members are expected~~environmental groups brought suit challenging the new rules almost immediately. Accordingly, legal uncertainty exists with respect to ~~own approximately 95%~~the future scope and extent of implementation of the ~~outstanding~~methane rule; however, even as currently implemented, these rules apply to our operations, including requirements for the installation of equipment to control VOC emissions from certain hydraulic fracturing of wells and fugitive emissions from well site and other production equipment, and additional regulation, which could result in significant costs, including increased capital ~~stock~~expenditures and operating costs, and could adversely impact or delay oil and natural gas production activities, which could have a material adverse effect on our business.

The federal Bureau of ~~the combined company~~Land Management (“BLM”) published a final rule in March 2015 that established new or more stringent standards relating to hydraulic fracturing on a fully diluted basis. Accordingly, the issuance of shares of the Company’s common stock to Riley’s members in the Merger will reduce significantly the relative voting power of each share of the Company’s common stock held by current stockholders of the Company. Consequently, the Company’s stockholders as a group will have significantly less influence over the management and policies of the combined company after the Merger than prior to the Merger.

~~Table of Contents~~

~~Use of TGC’s Net Operating Loss Carryforwards May Be Limited.~~

~~At December 31, 2019, TGC had, subject to the limitations discussed in this risk factor, substantial amounts of net operating loss carryforwards for U.S.~~ federal and ~~state income tax purposes. These loss carryforwards will eventually expire if not utilized. In addition, as to a portion~~American Indian lands. However, following years of litigation, the BLM rescinded the rule in December 2017. The BLM and the Secretary of the U.S. ~~net operating loss carryforwards, the amount of such carryforwards that TGC can use annually is limited under U.S. tax laws. Uncertainties exist as to both the calculation~~Department of the ~~appropriate deferred tax assets based upon~~Interior are now being sued for the ~~existence~~decision to rescind the rule. In April 2020, the Northern District of California issued a ruling in favor of the BLM and the Department of the Interior. This ruling is now being appealed; thus, the future of the rule remains uncertain. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances.

From time to time, legislation has been introduced in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, to date, such legislation has not been adopted. At the state level, Texas, where we conduct our operations, is among the states that has adopted regulations that

PART II: OTHER INFORMATION

impose new or more stringent permitting, including the requirement for hydraulic-fracturing operators to complete and submit a list of chemicals used during the fracking process. We may incur significant additional costs to comply with such existing state requirements and, in the event additional state level restrictions relating to the hydraulic-fracturing process are adopted in areas where we operate, we may become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.

Moreover, we typically dispose of flowback and produced water or certain other oilfield fluids gathered from oil and natural gas producing operations in underground disposal wells. This disposal process has been linked to increased induced seismicity events in certain areas of the country, particularly in Oklahoma, Texas, Colorado, Kansas, New Mexico and Arkansas. These and other states have begun to consider or adopt laws and regulations that may restrict or otherwise prohibit oilfield fluid disposal in certain areas or underground disposal wells, and state agencies implementing these ~~loss carryforwards,~~requirements may issue orders directing certain wells where seismic incidents have occurred to restrict or suspend disposal well operations or impose standards related to disposal well construction and monitoring. For example, in 2014, the Railroad Commission of Texas (“TRRC”) published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the ~~future utilization~~disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Any one or more of these developments may result in our having to limit disposal well volumes, disposal rates or locations, or to cease disposal well activities, which could have a material adverse effect on our business, financial condition, and results of operations.

In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. EPA has also brought attention to the reach of the ~~operating loss carryforwards~~CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. In a statement issued by EPA in April 2019, the agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, in April 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v. Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the ~~criteria~~CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. On December 8, 2020, EPA issued draft guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent” of a direct discharge based solely on proximity to jurisdictional waters. EPA is currently soliciting public comments on the guidance. The U.S. Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund could result in increased operational costs if permits are required under the CWA for disposal of our flowback and produced water in underground disposal wells.

Increased regulation and attention given to the hydraulic fracturing process and associated processes could lead to greater opposition to, and litigation concerning, oil and natural gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal, state or local laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and natural gas wells and an associated increase in compliance costs and time, which could have a material adverse effect on our liquidity, results of operations, and financial condition.

Climate change legislation and regulations restricting or regulating emissions of greenhouse gases could result in increased operating costs and reduced demand for the oil, natural gas and NGLs that we produce while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional, and state levels of government to monitor and limit emissions of greenhouse gases (“GHGs”). While no comprehensive climate change legislation has been implemented at the federal level, the EPA and states or groupings of states have pursued legal initiatives in recent years

PART II: OTHER INFORMATION

that seek to reduce GHG emissions through efforts that include consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs and regulations that directly limit GHG emissions from certain sources. In particular, the EPA has adopted rules under authority of the CAA that, among other things, establish certain permit reviews for GHG emissions from certain large stationary sources, which reviews could require securing permits at covered facilities emitting GHGs and meeting defined technological standards for those GHG emissions. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, including, among others, onshore production.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published a final rule establishing NSPS Subpart OOOOa, which requires certain new, modified or reconstructed facilities in the oil and natural gas sector to reduce these methane gas and VOC emissions. Although much of the initial rules remain intact and effective, the rules have been subject to legal challenges, reconsideration by EPA, stays, and proposed amendments. Most recently, on September 14 and 15, 2020, EPA published two new final rules in the Federal Register that remove the transmission and storage sectors of the oil and gas industry from regulation under the NSPS and rescind methane-specific standards for the production and processing segments of the industry. However, states and environmental groups brought suit challenging the new rules almost immediately. The BLM also finalized rules regarding the control of methane emissions in November 2016 that applied to oil and natural gas exploration and development activities on public and tribal lands. The rules sought to minimize venting and flaring of emissions from storage tanks and other equipment, and also impose leak detection and repair requirements. However, due to subsequent BLM revisions and multiple legal challenges, the rules were never fully implemented, and in October 2020, the November 2016 rules were struck down by the District Court of Wyoming as the result of one such challenge. Additionally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and “represent a progression” in their intended nationally determined contributions, which set ~~forth under FASB ASC 740, Income Taxes.~~GHG emission reduction goals every five years beginning in 2020. This “Paris Agreement” was signed by the United States in April 2016 and entered into force in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions. Although President Trump announced on June 1, 2017, that the United States plans to withdraw from the Paris Agreement and to seek negotiations either to re-enter the Paris Agreement on different terms or to establish a new framework agreement, the Paris Agreement provides for a four-year exit date of November 4, 2020, and President-Elect Joe Biden has pledged to rejoin the Paris Agreement on day one of his presidency. If he fulfills this pledge, the U.S.’s return to participation in the Paris Agreement would then become effective after a 30-day waiting period.

The adoption and implementation of any international, federal or state legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial condition, results of operations, and cash flows.

Finally, increasing concentrations of GHG in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such climatic events were to occur, they could have an adverse effect on our financial condition and results of operations and the financial condition and operations of our customers.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling, and place us at a competitive disadvantage. Potential disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance our operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.

Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which

PART II: OTHER INFORMATION

may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect threatened or endangered species and their habitats could prohibit drilling in certain areas or require the implementation of expensive mitigation or conservation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have a material adverse impact on our ability to develop and produce our reserves.

The enactment of derivatives legislation could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.

The Dodd-Frank Act, enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and of entities, such as us, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the Dodd-Frank Act. In December 2016, the CFTC re-proposed regulations implementing limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide hedging transactions. The Dodd-Frank Act and CFTC rules also will require us, in connection with certain derivatives activities, to comply with clearing and trade-execution requirements (or to take steps to qualify for an exemption to such requirements). In addition, ~~further limitations exist upon~~the CFTC and certain banking regulators have adopted final rules establishing minimum margin requirements for uncleared swaps. Although we expect to qualify for the end-user exception to the mandatory clearing, trade-execution and margin requirements for swaps entered to hedge our commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. In addition, if any of our swaps do not qualify for the commercial end-user exception, posting of collateral could impact liquidity and reduce cash available to us for capital expenditures, therefore reducing our ability to execute hedges to reduce risk and protect cash flow. It is not possible at this time to predict with certainty the full effects of the Dodd-Frank Act and CFTC rules on us or the timing of such effects. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, and reduce our ability to monetize or restructure our existing derivative contracts. If we reduce our use of ~~these carryforwards in the event that a change in control of TGC occurs, which is expected~~derivatives as a result of the ~~merger.~~Dodd-Frank Act and CFTC rules, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil, natural gas and NGL prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and NGLs. Our revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and CFTC rules is to lower commodity prices. Any of these consequences could have a material and adverse effect on us, our financial condition or our results of operations.

Future federal, state or local legislation also may impose new or increased taxes or fees on oil and natural gas extraction or production.

Future changes in U.S. federal income tax laws, as well as any similar changes in state law, could eliminate or postpone certain tax deductions that currently are available with respect to oil and gas development, or increase costs, and any such changes could have an adverse effect on our financial position, results of operations, and cash flows. Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction or production. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil, natural gas or NGLs.

Anti-indemnity provisions enacted by many states may restrict or prohibit a party’s indemnification of us.

We typically enter into agreements with our customers governing the use and operation of our systems, which usually include certain indemnification provisions for losses resulting from operations. Such agreements may require each party to indemnify the other against certain claims regardless of the negligence or other fault of the indemnified party; however, many states place limitations on contractual indemnity agreements, particularly agreements that indemnify a party against the consequences of its own negligence. Furthermore, certain states, including Louisiana, New Mexico, Texas and Wyoming have enacted statutes generally referred to as “oilfield anti-indemnity acts” expressly prohibiting certain indemnity agreements contained in or related to oilfield services agreements. Such anti-indemnity acts may restrict or void a party’s indemnification of us, which could have a material adverse effect on our business, financial condition, prospects and results of operations.

PART II: OTHER INFORMATION

Our effective tax rate may change in the future, which could adversely impact us.

The TCJA significantly changed the U.S. federal income taxation of U.S. corporations, including by reducing the U.S. corporate income tax rate, limiting interest deductions and certain deductions for executive compensation, permitting immediate expensing of certain capital expenditures, and revising the rules governing net operating losses. The TCJA remains unclear in some respects and continues to be subject to potential amendments and technical corrections. The United States Treasury Department and the IRS have issued significant guidance since the TCJA was enacted, interpreting the TCJA and clarifying some of the uncertainties, and are continuing to issue new guidance. There are still significant aspects of the TCJA for which further guidance is expected, and both the timing and contents of any such future guidance are uncertain.

Further, changes to the U.S. federal income tax laws are proposed regularly and there can be no assurance that, if enacted, any such changes would not have an adverse impact on us. For example, President Biden has suggested the reversal or modification of some portions of the TCJA and certain of these proposals, if enacted, could increase our effective tax rate. There can be no assurance that any such proposed changes will be introduced as legislation or, if introduced, later enacted, and, if enacted, what form such enacted legislation would take. Such changes could potentially have retroactive effect.

In light of these factors, there can be no assurance that our effective income tax rate will not change in future periods. If the effective tax rate were to increase as a result of the future legislation, our business could be adversely affected.

Risks Related to Our Common Stock

The market price of our common stock may be volatile, which could cause the value of your investment to decline.

The stock markets have experienced extreme volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock. The market price of our common stock may also fluctuate significantly in response to the following factors, some of which are beyond our control:

•our operating and financial performance and drilling locations, including reserve estimates;

•actual or anticipated fluctuations in our quarterly results of operations, and financial indicators, such as net income, cash flow and revenues;

•our failure to meet revenue, reserves or earnings estimates by research analysts or other investors;

•sales of our common stock by the Company or other stockholders, or the perception that such sales may occur;

•the public reaction to our press releases, other public announcements, and filings with the SEC;

•strategic actions by our competitors or competition for, among other things, capital, acquisition of reserves, undeveloped land and skilled personnel;

•publication of research reports about us or the oil and natural gas exploration and production industry generally;

•changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

•speculation in the press or investment community;

•the failure of research analysts to cover our common stock;

•increases in market interest rates or funding rates, which may increase our cost of capital;

•changes in market valuations of similar companies;

•changes in accounting principles, policies, guidance, interpretations or standards;

•additions or departures of key management personnel;

•actions by our stockholders;

•commencement or involvement in litigation;

•general market conditions, including fluctuations in commodity prices;

•political conditions in oil and gas producing regions;

•domestic and international economic, legal and regulatory factors unrelated to our performance; and

•the realization of any risks described under this “Risk Factors” section.

Moreover, the stock markets in general have experienced substantial volatility that ~~TGC~~has often been unrelated to the operating performance of individual companies. These broad market fluctuations may also adversely affect the trading price of our common stock.

In the past, following periods of volatility in the market price of a company’s securities, stockholders have often instituted class action securities litigation against those companies. Such litigation, if instituted, could result in substantial costs and

PART II: OTHER INFORMATION

diversion of management attention and resources, which could significantly harm our business, financial condition, results of operations and reputation.

Future sales or the possibility of future sales of a substantial amount of our commonstock may depress the price of shares of our common stock.

Future sales or the availability for sale of substantial amounts of our common stock in the public market could adversely affect the prevailing market price of our common stock and could impair our ability to raise capital through future sales of equity securities.

We may issue shares of our common stock or other securities from time to time as consideration for future acquisitions and investments. If any such acquisition or investment is significant, the number of shares of our common stock, or the number or aggregate principal amount, as the case may be, of other securities that we may issue may in turn be substantial. We may also grant registration rights covering those shares of our common stock or other securities in connection with any such acquisitions and investments.

We cannot predict the size of future issuances of our common stock or the effect, if any, that future issuances and sales of our common stock will have on the market price of our common stock. Sales of substantial amounts of our common stock (including shares of our common stock issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices for our common stock.

If we fail to continue to meet the requirements for continued listing on the NYSE American stock exchange, our common stock could be delisted from trading, which would decrease the liquidity of our common stock and ability to raise additional capital.

Our common stock is listed for quotation on the NYSE American and we are required to meet specified financial requirements, including requirements for a minimum amount of capital, a minimum price per share, a minimum public float, and continued business operations so that we are not delisted or characterized as a “public shell company.” If we are unable to comply with the NYSE American stock exchange’s listing standards, NYSE may determine to delist our common stock from the NYSE American stock exchange or other of NYSE’s trading markets. If our common stock is delisted for any reason, it could reduce the value of our common stock and liquidity.

If securities analysts do not publish research or reports about our business or if they publish negative evaluations of our stock, the price of our stock could decline.

The trading market for our common stock relies, in part, on the research and reports that industry or financial analysts publish about us or our business. Equity research analysts may elect not to provide research coverage of our common stock, and such lack of research coverage may adversely affect the market price of our common stock. In the event we do have equity research analyst coverage, we will not have any control over the analysts or the content and opinions included in their reports. The price of our common stock could decline if one or more equity research analysts downgrade our stock or issue other unfavorable commentary or research. If one or more equity research analysts ceases coverage of us or fails to publish reports on us regularly, demand for our common stock could decrease, which in turn could cause our stock price or trading volume to decline.

We may not generate sufficient cash to support any dividend to our common stockholders.

The amount of any dividend will depend on the amount of cash we generate from operations, which will fluctuate from quarter to quarter based on, among other things:

PART II: OTHER INFORMATION

•

the volumes of crude oil, natural gas and NGLs that we produce;

•

market prices of crude oil, natural gas and NGLs and their effect on our drilling and development plan;

•

the levels of our operating expenses, maintenance expenses and general and administrative expenses;

•

regulatory action affecting:

•

the supply of, or demand for, crude oil, natural gas and NGLs;

•

our operating costs or our operating flexibility;

•

prevailing economic conditions; and

•

adverse weather conditions.

In addition, the actual amount of cash we will have available for dividends will depend on other factors, some of which are beyond our control, including:


•			our debt service requirements and other liabilities;
•			our ability to borrow under our debt agreements to fund our capital expenditures and operating expenditures and to pay dividends;
•			fluctuations in our working capital needs;
•			restrictions on dividends contained in any of our debt agreements;
•			the cost of acquisitions, if any; and
•			other business risks affecting our cash levels.

Our quarterly cash dividends, if any, may vary significantly both quarterly and annually.

Investors who are looking for an investment that will pay regular and predictable quarterly dividends should not invest in our common stock. Our business performance may be more volatile, and our cash flow may be less stable, than other business models that pay dividends. The amount of our quarterly dividends will generally depend on the performance of our business, which has a limited operating history.

The board of directors may modify or revoke our dividend policy at any time at its discretion.

We are not required to pay any dividends on our common stock at all. Accordingly, the board of directors may change our dividend policy at any time at its discretion and could elect not to pay dividends on our common stock for one or more quarters. Any modification or revocation of our cash dividend policy could substantially reduce or eliminate the amounts of dividends to our common stockholders. The amount of dividends we make, if any, and the decision to make any dividend at all will be determined by our board of directors, whose interests may differ from those of our common stockholders.

The amount of cash we have available for dividends to our common stockholders depends primarily on our cash flow and not solely on our profitability, which may prevent us from paying dividends, even during periods in which we record net income.

The amount of cash we have available for dividends depends primarily upon our cash flow and not solely on our profitability, which will be affected by non-cash items. As a result, we may pay cash dividends during periods when we record a net loss for financial accounting purposes and, conversely, we might fail to pay cash dividends on our common stock during periods when we record net income for financial accounting purposes.

Delaware law imposes restrictions on our ability to pay cash dividends on our common stock.

Our common stockholders do not have a right to dividends on such shares unless declared or set aside for payment by our board of directors. Under Delaware law, cash dividends on capital stock may only be paid from “surplus” or, if there is no “surplus,” from the corporation’s net profits for the then-current or the preceding fiscal year. Unless we operate profitably, our ability to pay dividends on our common stock would require the availability of adequate “surplus,” which is defined as the excess, if any, of net assets (total assets less total liabilities) over capital. Our business may not generate sufficient surplus or net profits from operations to enable us to pay dividends on our common stock.

We have identified several material weaknesses in our internal control over financial reporting as of March 31, 2021 and may identify additional material weaknesses in the future, or otherwise fail to maintain an effective system of

PART II: OTHER INFORMATION

internal controls, which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations.

As of March 31, 2021, we have identified material weaknesses in our internal control over financial reporting. In particular, we had not yet designed an effective financial reporting process and did not complete thorough reviews of financial reports in a timely manner to allow for an appropriate level of analysis that would have identified these errors. These errors principally related to (i) accounting for stock-based compensation and our failure to record compensation expense for certain vested stock-based compensation grants in the correct reporting period, (ii) accounting for dividend distributions and our failure to record a declared dividend in the reporting period in which the dividend was declared, (iii) accounting for derivative settlements, and (iv) controls over preparation and review of the Company’s statement of cash flows were not effective. As of the date hereof, we have not fully re-designed, implemented and tested internal controls to remediate the material weaknesses.

The controls after the Merger are now the controls which REP LLC had in place prior to the Merger. Our management is in the process of developing its remediation plan to address the material weaknesses identified in the quarter, which we expect to include implementing additional review procedures within our accounting departments. These plans are subject to ongoing management review. The material weaknesses identified above will not be considered remediated until our remediation efforts have been fully implemented and we have concluded that these controls are operating effectively. Although we believe our plan will address the internal control deficiencies that led to the material weaknesses, the measures we plan to take may not be effective. Consequently, if these or another material weakness or significant deficiencies occur in the future, it could affect the financial results that we report which could result in a restatement of our financial statements or cause us to fail to meet our reporting obligations.

If we fail to maintain an effective system of internal control over financial reporting, we may not be able to ~~utilize some~~accurately report our financial results or ~~all~~prevent fraud. As a result, stockholders could lose confidence in our financial and other public reporting, which would harm our business and the trading price of our common stock.

Effective internal control over financial reporting is necessary for us to provide reliable financial reports and, together with adequate disclosure controls and procedures, is designed to prevent fraud. Any failure to implement required new or improved controls, or difficulties encountered in their implementation, could cause us to fail to meet our reporting obligations. In addition, any testing, as and when required, conducted in connection with Section 404 of the ~~remaining carryforwards,~~Sarbanes-Oxley Act, or Section 404, or any subsequent testing by our independent registered public accounting firm, as and when required, may reveal deficiencies in our internal control over financial reporting that are deemed to be significant deficiencies or material weaknesses or that ~~deferred tax assets that were previously booked based upon such carryforwards~~ may require prospective or retroactive changes to our financial statements or identify other areas for further attention or improvement. Inferior internal controls could also cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our common stock.

We are a smaller reporting company and we cannot be ~~written down or reversed based on future economic factors that may be experienced~~certain if the reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.

We are currently a “smaller reporting company” as defined by TGC. The effect of such write downs or reversals, if they occur, may be material and substantially adverse. At December 31, 2019, federal net operating loss carryforwards amounted to approximately $33.8 million, of which $31.5 million expires between 2020 and 2037 which can offset 100% of taxable income and $2.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was $65,000 at December 31, 2019 and $130,000 at 2018. In 2018, TGC released a portionRule 12b-2 of the ~~allowance related~~Exchange Act. As a “smaller reporting company,” we are subject to ~~its Minimum Tax Credit~~reduced disclosure obligations in our SEC filings compared to other issuers, including, among other things, an exemption from the requirement to present five years of selected financial data, being required to provide only two years of audited financial statements in annual reports and being subject to simplified executive compensation disclosures. Until such time as we cease to be a “smaller reporting company,” such reduced disclosure in our SEC filings may make it harder for investors to analyze our operating results and financial prospects. If some investors find our common stock less attractive as a result of ~~comprehensive tax reform legislation enacted~~any choices to reduce disclosure we may make, there may be a less active trading market for our common stock and our stock price may be more volatile.

We may issue preferred stock whose terms could adversely affect the voting power or value of our common stock.

Our certificate of incorporation authorizes us to issue, without the approval of our shareholders, one or more classes or series of preferred stock having such designations, preferences, limitations and relative rights, including preferences over our common stock respecting dividends and distributions, as our board of directors may determine. The terms of one or more classes or series of preferred stock could adversely impact the voting power or value of our common stock. For example, we might grant holders of preferred stock the right to elect some number of our directors in ~~December 2017, commonly referred~~all events or on the

PART II: OTHER INFORMATION

happening of specified events or the right to asveto specified transactions. Similarly, the ~~Tax Cuts~~repurchase or redemption rights or liquidation preferences we might assign to holders of preferred stock could affect the residual value of the common stock.

Risks Related to the Company

Our business and ~~Jobs Act (the “TCJA”). TGC recorded an allowance~~operations could be adversely affected if we lose key personnel.

We depend to a large extent on the ~~remaining deferred tax asset at December 31, 2019 primarily due~~services of our officers, including Bobby Riley, our Chief Executive Officer, Kevin Riley, our President, Michael Rugen, our Chief Financial Officer, Corey Riley, our Executive Vice President Business Development, Philip Riley, our Executive Vice President Strategy, and Michael Palmer, our Executive Vice President Corporate Land. These individuals have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties and developing and executing financing strategies. The loss of any of these individuals could have a material adverse effect on our operations. We do not maintain key-man life insurance with respect to ~~expected future losses~~any management personnel. Our success will be dependent on our ability to continue to retain and utilize skilled technical personnel. The loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition, and results of operations.

Our executive officers, directors and principal stockholders have the ability to control or significantly influence all matters submitted to the Company’s stockholders for approval.

Our executive officers, directors and principal stockholders, in the ~~near term which would cause cumulative losses being incurred during the 3 year period. TGC recorded a full allowance against the deferred tax asset net~~aggregate, own 87.8% of the alternative minimum tax (“AMT”) credit at December 31, 2018 primarily due to cumulative losses incurred during the 3 years ended December 31, 2018. The total valuation allowance December 31, 2019 was $10.7 million, and $11.5 million at December 31, 2018.

~~ITEM 2.~~

~~UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~

~~None.~~

~~ITEM 3.~~

~~DEFAULTS UPON SENIOR SECURITIES~~

~~None.~~

~~ITEM 4.~~

~~MINE SAFETY DISCLOSURES~~

~~Not Applicable~~

~~ITEM 5.~~

~~OTHER INFORMATION~~

On October 21, 2020, the Company, Merger Sub, and Riley, entered the Merger Agreement pursuant to which Merger Sub will be merged with and into Riley, with Riley surviving the Merger as a wholly owned subsidiaryfully diluted common stock of the Company. ~~On the terms and subject~~As a result, if these stockholders were to choose to act together, they would be able to control or significantly influence all matters submitted to the ~~conditions set forth in~~Company’s stockholders for approval, as well as the ~~Merger Agreement, upon consummation~~Company’s management and affairs. For example, these persons, if they choose to act together, would control or significantly influence the election of ~~the Merger, each common unit~~directors and approval of ~~Riley issued and outstanding immediately prior to the effective time~~any merger, consolidation or sale of ~~the Merger (other than cancelled units (as defined in the Merger Agreement)) will be converted into the right to receive: (a) 97.796467 shares~~all or substantially all of the Company’s ~~common stock (together with any cash to be paid in lieu~~assets. This concentration of ~~fractional shares~~voting power could delay or prevent an acquisition of the Company ~~Common Stock)~~on terms that other stockholders may desire.

Provisions in our corporate charter documents and ~~(b) any dividends~~under Delaware law could make an acquisition of the Company, which may be beneficial to our stockholders, more difficult and may prevent attempts by our stockholders to replace or remove current management.

Provisions in our corporate charter and by-laws may discourage, delay or prevent a merger, acquisition or other ~~distributions~~changes in control that stockholders may consider favorable, including transactions in which stockholders might otherwise receive a premium for their shares. These provisions also could limit the price that investors might be willing to pay in the future for shares of our common stock, thereby depressing the market price of our common stock. In addition, because our board of directors is responsible for appointing the members of the management team, these provisions may frustrate or prevent any attempts by our stockholders to replace or remove current management by making it more difficult for stockholders to replace members board of directors. Among other things, these provisions:


•			allow the authorized number of directors to be changed only by resolution of the board of directors;
•			after a certain date, limit the manner in which stockholders can remove directors from the board;
•			establish advance notice requirements for stockholder proposals that can be acted on at stockholder meetings and nominations to the board of directors;
•			after a certain date, require that stockholder actions must be effected at a duly called stockholder meeting and prohibit actions by written consent;
•			limit who may call stockholder meetings;
•			authorize the board of directors to issue preferred stock without stockholder approval, which could be used to institute a shareholder rights plan, or so-called “poison pill,” that would work to dilute the stock ownership of a potential hostile acquirer, effectively preventing acquisitions that have not been approved by the board of directors; and
•			after a certain date, require the approval of the holders of at least 66 2/3% of the votes that all the stockholders would be entitled to cast to amend or repeal certain provisions of our charter or bylaws.

PART II: OTHER INFORMATION

Our bylaws provide that the Court of Chancery of the State of Delaware will be the exclusive forum for substantially all disputes between the Company and its stockholders, which could limit stockholders’ ability to obtain a favorable judicial forum for disputes with the Company or its directors, officers, employees or stockholders.

Our bylaws provide that, unless the Company consents in writing to the selection of an alternative forum, the Court of Chancery of the State of Delaware is the exclusive forum for any derivative action or proceeding brought on the Company’s behalf, any action asserting a breach of fiduciary duty owed by Company’s directors, officers, other employees or stockholders to the Company or its stockholders, any action asserting a claim against the Company arising pursuant to the Delaware General Corporation Law or as to which the ~~holder~~Delaware General Corporation Law confers jurisdiction on the Court of Chancery of the State of Delaware, or any action asserting a ~~Riley common unit becomes entitled~~claim arising pursuant to ~~upon~~ the ~~surrender~~Company’s certificate of ~~such Riley common unit~~incorporation or bylaws or governed by the internal affairs doctrine.

Our bylaws provide that, unless the Company consents in ~~accordance~~writing to the selection of an alternative forum, the federal district courts of the United States of America shall, to the fullest extent permitted by law, be the sole and exclusive forum for any actions arising under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended.

These provisions may limit a stockholder’s ability to bring a claim in a judicial forum that it finds favorable for disputes with the ~~Merger Agreement.~~

~~Additional information regarding~~Company or its directors, officers, employees or stockholders, which may discourage such lawsuits against the ~~Merger~~Company’s and ~~the Merger Agreement can~~its directors, officers, employees or stockholders. Alternatively, if a court were to find these provisions in our bylaws to be ~~found~~inapplicable or unenforceable in ~~(a) the press release issued by~~an action, the Company may incur additional costs associated with resolving such action in other jurisdictions, which could adversely affect our business and financial condition.

Conflicts of interest could arise in the future between us, on ~~October 21, 2020~~the one hand, and ~~(b)~~certain of our stockholders and their respective affiliates, including their funds and their respective portfolio companies, on the ~~Current Report~~other hand, concerning among other things, potential competitive business activities or business opportunities.

Investment funds managed by certain of our stockholders are in the business of making investments in entities in the U.S. energy industry. As a result, certain of our stockholders may, from time to time, acquire interests in businesses that directly or indirectly compete with our business, as well as businesses that are significant existing or potential customers. Certain of our stockholders and their respective portfolio companies may acquire or seek to acquire assets that we seek to acquire and, as a result, those acquisition opportunities may not be available to us or may be more expensive for us to pursue. Under our certificate of incorporation, certain of our stockholders and/or one or more of their respective affiliates are permitted to engage in business activities or invest in or acquire businesses which may compete with our business or do business with any client of ours. Any actual or perceived conflicts of interest with respect to the foregoing could have an adverse impact on ~~Form 8-K filed by~~ the ~~Company on October 22, 2020.~~trading price of our common stock.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Not applicable.

Item 3. Defaults Upon Senior Securities

Not applicable.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

Not applicable.

PART II: OTHER INFORMATION

~~Table of Contents~~Item 6. Exhibits

~~Delaware~~	~~87-0267438~~
Delaware		08-0267438
(State or other jurisdiction of incorporation or organization)		(~~IRS~~I.R.S. Employer Identification No.)

29 E. Reno Avenue, Suite 500 Oklahoma City, Oklahoma		73104
(Address of Principal Executive Offices)		(Zip Code)


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common stock, par value $0.001	REPX	NYSE American


Large accelerated filer ☐	o	Accelerated filer ☐	o
Non-accelerated filer ☐	x	Smaller reporting company ☒	x
		Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐	o

~~Title of each class~~	~~Trading Symbol(s)~~	~~Name of each exchange on which registered~~
~~Common Stock~~	~~TGC~~	~~NYSE American~~

		~~PAGE~~
Riley Exploration Permian, Inc.
Table of Contents
			For the Quarter Ended March 31, 2021
				Page
Part I. Financial Information
~~PART I.~~Item 1.			~~FINANCIAL INFORMATION~~Financial Information	5
			~~ITEM 1. FINANCIAL STATEMENTS~~
	* Unaudited Condensed Consolidated Balance Sheets ~~as of September 30, 2020 and December 31, 2019~~	3 5
			* Unaudited Condensed Consolidated Statements of Operations ~~for the three months and nine months ended September 30, 2020 and 2019~~	5 7
			* Unaudited Condensed Consolidated Statements of Changes in Members'/Shareholders ' Equity	9
			Condensed Consolidated Statements of Cash Flows ~~for the nine months ended September 30, 2020 and 2019~~	6 11
			* Unaudited Changes in Stockholders’ Equity for the three months and nine months ended September 30, 2020 and 2019	7
	* Notes to ~~Unaudited~~ Condensed Consolidated Financial Statements	8
	~~ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS~~13	18
	~~ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK~~	20
	~~ITEM 4. CONTROLS AND PROCEDURES~~	22
~~PART II.~~Item 2.			~~OTHER INFORMATION~~Management's Discussion and Analysis of Financial Condition and Results of Operations	22 36
Item 3.			~~ITEM 1. LEGAL PROCEEDINGS~~Quantitative and Qualitative Disclosures About Market Risk	22 50
Item 4.			~~ITEM 1A. RISK FACTORS~~Controls and Procedures	22 51
				~~ITEM 2. UNREGISTERD SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~Part II. Other Information	24
Item 1.			~~ITEM 3. DEFAULTS UPON SENIOR SECURITIES~~Legal Proceedings	24 53
Item 1A.			~~ITEM 4. MINE SAFTY DISCLOSURES~~Risk Factors	24 53
Item 2.			~~ITEM 5. OTHER INFORMATION~~Unregistered Sales of Equity Securities and Use of Proceeds	24 83
Item 3.			~~ITEM 6. EXHIBITS~~Defaults Upon Senior Securities	25 83
Item 4.			* SIGNATURESMine Safety Disclosures	26 83
Item 5.			* CERTIFICATIONS Other Information	83
Item 6.			Exhibits	84

Signatures


x			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934


o			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	September 30, 2020		December 31, 2019
Assets

Current
Cash and cash equivalents	$	2,545	$	3,055
Accounts receivable		262		557
Inventory		302		415
Prepaid expenses		156		247
Other current assets		4		4
Total current assets		3,269		4,278
Loan fees, net		2		4
Right of use asset - operating leases		58		41
Oil and gas properties, net (full cost accounting method)		3,914		4,385
Other property and equipment, net		134		149
Accounts receivable - noncurrent		—		65
Total assets	$	7,377	$	8,922

	September 30, 2020			December 31, 2019
Liabilities and Stockholders’ Equity

Current liabilities
Accounts payable – trade	$	304		$	269
Accrued liabilities		255			164
Lease liabilities - operating leases - current		58			41
Lease liabilities - finance leases - current		58			61
Current maturities long-term debt		101			—
Asset retirement obligation - current		75			75
Total current liabilities		851			610
Lease liabilities - finance leases - noncurrent		42			41
Long-term debt, less current maturities		65			—
Asset retirement obligation - noncurrent		1,954			1,923
Total liabilities		2,912			2,574
Commitments and contingencies (Note 10)
Stockholders’ equity
Preferred stock, 25,000,000 shares authorized:
Series A Preferred stock, $0.0001 par value, 10,000 shares designated; 0 shares issued and outstanding		—			—
Common stock, $0.001 par value, authorized 100,000,000 shares, 10,680,050 and 10,658,775 shares issued and outstanding		11			11
Additional paid–in capital		58,304			58,293
Accumulated deficit		(53,850	)		(51,956	)
Total stockholders’ equity		4,465			6,348
Total liabilities and stockholders’ equity	$	7,377		$	8,922

	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2020			2019			2020			2019
Revenues
Oil and gas properties	$	765		$	1,215		$	2,292		$	3,777
Total revenues		765			1,215			2,292			3,777
Cost and expenses
Production costs and taxes		746			913			2,399			2,604
Depreciation, depletion, and amortization		146			186			461			566
General and administrative		685			297			1,324			913
Total cost and expenses		1,577			1,396			4,184			4,083
Net loss from operations		(812	)		(181	)		(1,892	)		(306	)
Other income (expense)
Interest expense		(2	)		(2	)		(6	)		(8	)
Gain on sale of assets		1			1			4			45
Total other income (expense)		(1	)		(1	)		(2	)		37
Net loss from operations before income tax		(813	)		(182	)		(1,894	)		(269	)
Deferred income tax benefit (expense)		—			—			—			—
Net loss	$	(813	)	$	(182	)	$	(1,894	)	$	(269	)
Net loss per share
Basic and fully diluted	$	(0.08	)	$	(0.02	)	$	(0.18	)	$	(0.03	)
Shares used in computing earnings per share
Basic and fully diluted		10,680,050			10,653,550			10,673,238			10,648,838

Nine Months Ended September 30, 2020:
	Common Stock				Paid-in Capital		Accumulated Deficit			Total
	Shares		Amount		Paid-in Capital		Accumulated Deficit			Total
Balance, December 31, 2019		10,658,775	$	11	$	58,293	$	(51,956	)	$	6,348

Net loss		—		—		—		(527	)		(527	)
Compensation expense related to stock issued		7,436		—		4		—			4

Balance, March 31, 2020		10,666,211	$	11	$	58,297	$	(52,483	)	$	5,825

Net loss		—		—		—		(554	)		(554	)
Compensation expense related to stock issued		7,328		—		3		—			3

Balance, June 30, 2020		10,673,539	$	11	$	58,300	$	(53,037	)	$	5,274

Net loss		—		—		—		(813	)		(813	)
Compensation expense related to stock issued		6,511		—		4		—			4

Balance, September 30, 2020		10,680,050	$	11	$	58,304	$	(53,850	)	$	4,465

Nine Months Ended September 30, 2019:
	Common Stock				Paid-in		Accumulated
	Shares		Amount		Capital		Deficit			Total
Balance, December 31, 2018		10,639,290	$	11	$	58,276	$	(51,520	)	$	6,767

Net loss		—		—		—		(96	)		(96	)
Compensation expense related to stock issued		4,962		—		4		—			4

Balance, March 31, 2019		10,644,252	$	11	$	58,280	$	(51,616	)	$	6,675

Net income		—		—		—		9			9
Compensation expense related to stock issued		4,411		—		6		—			6

Balance, June 30, 2019		10,648,663	$	11	$	58,286	$	(51,607	)	$	6,690

Net loss		—		—		—		(182	)		(182	)
Compensation expense related to stock issued		4,887		—		4		—			4

Balance, September 30, 2019		10,653,550	$	11	$	58,290	$	(51,789	)	$	6,512

	September 30, 2020		December 31, 2019
Oil – carried at lower of cost or market	$	302	$	415
Total inventory	$	302	$	415

	September 30, 2020		December 31, 2019
Revenue	$	259	$	415
Tax		—		65
Joint interest		3		77
Accounts receivable - current	$	262	$	557

Tax - noncurrent	$	—	$	65

Balance December 31, 2019	$	1,998
Accretion expense		94
Liabilities incurred		—
Liabilities settled		—
Liabilities relieved - sold properties		(63	)
Balance September 30, 2020	$	2,029


NOT APPLICABLE

		Period Ended
		For the Three Months Ended				For the Nine Months Ended
	Statement of Operations Account	September 30, 2020		September 30, 2019		September 30, 2020		September 30, 2019

Operating lease cost:
	Production costs and taxes	$	3	$	3	$	10	$	10
	General and administrative		13		12		37		37
Total operating lease cost		$	16	$	15	$	47	$	47

Finance lease cost:
Amortization of right of use assets	Depreciation, depletion, and amortization	$	20	$	21	$	56	$	62
Interest on lease liabilities	Net interest expense		1		1		4		4
Total finance lease cost		$	21	$	22	$	60	$	66

	Balance Sheet as of
	September 30, 2020			December 31, 2019

Operating Leases:

Right of use asset - operating leases	$	58		$	41

Lease liabilities - current	$	58		$	41
Lease liabilities - noncurrent		—			—
Total operating lease liabilities	$	58		$	41


Finance Leases:

Other property and equipment, gross	$	293		$	295
Accumulated depreciation		(159	)		(146	)
Other property and equipment, net	$	134		$	149

Lease liabilities - current	$	58		$	61
Lease liabilities - noncurrent		42			41
Total finance lease liabilities	$	100		$	102

	Operating Leases			Finance Leases

Weighted average remaining lease term	0.9 years			1.1 years
Weighted average discount rate		3.75	%		5.35	%

~~ITEM 6.~~
Exhibit Number			Description

2.1			Agreement and Plan of Merger, by and among Tengasco, Inc., Antman Sub, LLC, and Riley Exploration - Permian, LLC, dated as of October 21, 2020 (incorporated by reference from Exhibit 2.1 to the Registrant’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 22, 2020).
2.2			Amendment No. 1 to Agreement and Plan of Merger, by and among Tengasco, Inc., Antman Sub, LLC, and Riley Exploration - Permian, LLC, dated as of January 20, 2021 (incorporated by reference from Exhibit 2.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on January 22, 2021).
3.1			First Amended and Restated Certificate of Incorporation of Riley Exploration Permian, Inc. (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-8 filed with the Securities and Exchange Commission on March 1, 2021, Registration No. 333-253750).
3.2~~EXHIBITS~~			Second Amended and Restated Bylaws of Riley Exploration Permian, Inc. (incorporated by reference to Exhibit 4.2 to the Registrant’s Registration Statement on Form S-8 filed with the Securities and Exchange Commission on March 1, 2021, Registration No. 333-253750).
10.1			Credit Agreement dated as of September 28, 2017, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.1 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.2			First Amendment to Credit Agreement dated as of February 27, 2018, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.2 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.3			Second Amendment to Credit Agreement dated as of November 9, 2018, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.3 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.4			Third Amendment to Credit Agreement dated as of April 3, 2019, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.4 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.5			Fourth Amendment to Credit Agreement dated as of October 15, 2019, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.5 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.6			Fifth Amendment to Credit Agreement dated as of May 7, 2020, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.6 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.7			Sixth Amendment to Credit Agreement dated as of August 31, 2020, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.7 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.8			Seventh Amendment and Consent to Credit Agreement dated as of October 21, 2020, by and among Riley Exploration – Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto (incorporated by reference from Exhibit 10.8 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.9 *			Eighth Amendment to Credit Agreement dated as of March 5, 2021, by and among Riley Exploration Permian, Inc., Riley Exploration - Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto.


10.10 *			Ninth Amendment to Credit Agreement dated as of May 5, 2021, by and among Riley Exploration Permian, Inc., Riley Exploration - Permian, LLC, as borrower, Truist Bank, as administrative agent, and the lenders party thereto.
31*10.11			Form of Indemnity Agreement (incorporated by reference from Exhibit 10.14 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on January 21, 2021, Registration No. 333-250019).
10.12			Form of Independent Director Agreement (incorporated by reference from Exhibit 10.13 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on January 21, 2021, Registration No. 333-250019).
10.13†			Riley Exploration Permian, Inc. 2021 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K filed with the Commission on February 25, 2021).
10.14†			Form of Common Stock Award Agreement (incorporated by reference from Exhibit 10.10 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).
10.15†			Form of Restricted Stock Agreement (Time Vesting) (incorporated by reference to Exhibit 4.4 to the Registrant’s Registration Statement on Form S-8, as filed with the Securities and Exchange Commission on March 1, 2021, Registration No. 333- 253750).
10.16†			Form of Substitute Restricted Stock Agreement (Time Vesting) (incorporated by reference from Exhibit 4.5 to the Registrant’s Registration Statement on Form S-8 filed with the Commission on March 1, 2021, Registration No. 333-253750).
10.17†			Form of Restricted Stock Agreement (Non-Employee Director) (incorporated by reference from Exhibit 4.6 to the Registrant’s Registration Statement on Form S-8 filed with the Commission on March 1, 2021, Registration No. 333-253750).
10.18†			Employment Agreement dated effective as of March 15, 2021 by and between Riley Exploration Permian, Inc. and Corey Riley (incorporated by reference from Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).
10.19†			Employment Agreement dated effective as of March 15, 2021 by and between Riley Exploration Permian, Inc. and Philip Riley (incorporated by reference from Exhibit 10.2 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).
10.20†			Employment Agreement dated effective as of February 26, 2021 by and between Riley Exploration Permian, Inc. and Michael J. Rugen (incorporated by reference from Exhibit 10.15 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 4, 2021).
10.21†			Employment Agreement dated April 1, 2019 by and between Riley Exploration – Permian, LLC and Bobby D. Riley and assigned by Riley Exploration – Permian, LLC to Riley Permian Operating Company, LLC on June 8, 2019 (incorporated by reference from Exhibit 10.9 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.22†			Amendment No. 1 to Employment Agreement dated October 1, 2020 by and between Riley Permian Operating Company, LLC and Bobby D. Riley (incorporated by reference from Exhibit 10.10 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
10.23†			Amendment No. 2 to Employment Agreement dated March 15, 2021 by and between Riley Permian Operating Company, LLC and Bobby D. Riley (incorporated by reference from Exhibit 10.7 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).
10.24†			Employment Agreement dated April 1, 2019 by and between Riley Exploration – Permian, LLC and Kevin Riley and assigned by Riley Exploration – Permian, LLC to Riley Permian Operating Company, LLC on June 8, 2019 (incorporated by reference from Exhibit 10.11 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019)
10.25†			Amendment No. 1 to Employment Agreement dated March 15, 2021 by and between Riley Permian Operating Company, LLC and Kevin Riley (incorporated by reference from Exhibit 10.8 to the Registrant’s Current Report on Form 8-K, as filed with the Securities and Exchange Commission on March 15, 2021).


10.26	Second Amended and Restated Registration Rights Agreement dated October 7, 2020 by and among Riley Exploration – Permian, LLC, Riley Exploration Group, Inc., Yorktown Energy Partners XI, L.P., Boomer Petroleum, LLC, Bluescape Riley Exploration Holdings LLC, Bluescape Riley Acquisition Company LLC, Bobby D. Riley, Kevin Riley and Corey Riley (incorporated by reference to Exhibit 4.1 to the Registrant’s Registration Statement on Form S-4/A, as filed with the Securities and Exchange Commission on December 31, 2020, Registration No. 333-250019).
31.1*	Certification of ~~the~~ Chief Executive Officer ~~and~~pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to ~~Exchange~~Section 302 of the Sarbanes-Oxley Act ~~Rule, Rule 13a-14a/15d-14a.~~of 2002
	3232.1	Certification of ~~the~~ Chief Executive Officer ~~and~~pursuant to 18 U.S.C., Section 1350 as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*	Certification of Chief Financial Officer pursuant to 18 ~~U.S.C~~U.S.C., Section 1350 as adopted pursuant to ~~section~~Section 906 of the Sarbanes-Oxley Act of ~~2002.~~2002
101.INS*	~~101.INS~~		XBRL Instance Document
101.SCH*	~~101.SCH~~		XBRL Taxonomy Extension Schema Document
101.CAL*	~~101.CAL~~		XBRL Taxonomy Calculation Linkbase Document
101.DEF*	~~101.DEF~~		XBRL Taxonomy Definition Linkbase Document
101.LAB*	~~101.LAB~~		XBRL Taxonomy Label Linkbase Document
101.PRE*	~~101.PRE~~		XBRL Taxonomy Presentation Linkbase Document

~~Dated: November 12, 2020~~
		RILEY EXPLORATION PERMIAN, INC.
~~TENGASCO, INC.~~
Date: May 17, 2021		By: /s/ Bobby D. Riley
~~By:~~	~~/s/~~	Bobby D. Riley
		Chief Executive Officer

		By: /s/ Michael J. Rugen
		Michael J. Rugen
	~~Chief Executive Officer and~~	Chief Financial Officer