10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

REPORT ON FORM 10-K

(Mark one)

☒ Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2020 or

☐ Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from __________ to __________.

Commission File No. 1-15555

Riley Exploration Permian, Inc.

(name of registrant as specified in its charter)

Delaware	87-0267438
(state or other jurisdiction of Incorporation or organization)	(I.R.S. Employer Identification No.)
29 E. Reno Avenue, Suite 500, Oklahoma City, OK	73104
(Address of Principal Executive Offices)	(Zip Code)

Registrant’s telephone number, including area code: (405) 415-8677

Securities registered pursuant to Section 12(b) of the Act: None.

Securities registered pursuant to Section 12(g) of the Act: Common Stock, $.001 par value per share.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.   Yes ☐    No ☒

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.   Yes ☐    No ☒

Indicated by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   Yes ☒    No ☐

Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files)   Yes ☒    No ☐

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K (§229.405 of this Chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer   ☐	Accelerated Filer   ☐
Non-accelerated Filer   ☐	Smaller Reporting Company  ⌧
(Do not check if a Smaller Reporting Company)	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  ☐

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes ☐    No ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $2.9 million (June 30, 2020 closing price $6.60 – stock price has been adjusted for the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021).

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common Stock	REPX	NYSE American

The number of shares outstanding of the registrant’s $.001 par value common stock as of the close of business on December 31, 2020 was approximately 890,420 (this share count has been adjusted for the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021).

Table of Contents

PART I			Page
	Item 1.	Business	6
	Item 1A.	Risk Factors	12
	Item 1B.	Unresolved Staff Comments	20
	Item 2.	Properties	20
	Item 3.	Legal Proceedings	23
	Item 4.	Mine Safety Disclosures	23
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	23
	Item 6.	Selected Financial Data	24
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	28
	Item 8.	Financial Statements and Supplementary Data	29
	Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	29
	Item 9A.	Controls and Procedures	29
	Item 9B.	Other Information	30
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	31
	Item 11.	Executive Compensation	35
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholders Matters	38
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	40
	Item 14.	Principal Accounting Fees and Services	42
PART IV	Item 15.	Exhibits, Financial Statement and Schedules	43
		SIGNATURES	44

2

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

Certain statements contained in this Report may contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, and Section 21E of the Securities Exchange Act of 1934, as amended. Words and phrases such as “should”, “could”, “may”, “will”, “believe”, “plan”, “intend”, “expect”, “potential”, “possible”, “anticipate”, “estimate”, “forecast”, “view”, “efforts”, “goal” and similar expressions identify forward-looking statements and express our expectations about future events. Although we believe the expectations reflected in such forward-looking statements are reasonable, such expectations may not occur. These forward-looking statements are made subject to certain risks and uncertainties that could cause actual results to differ materially from those stated, include the following risks:

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

• the impact of 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 transition to a cash-return business model, including the implementation of a dividend strategy;

• 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 covenant contained in our amended and restated 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; and

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

3

GLOSSARY OF OIL AND GAS TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and this document:

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of gas.

BOE. One stock tank barrel equivalent of oil, calculated by converting gas volumes to equivalent oil barrels at a ratio of 6 thousand cubic feet of gas to 1 barrel of oil.

BOPD. Barrels of oil per day.

Btu. British thermal unit. One British thermal unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential. An adjustment to the price of oil or gas from an established spot market price to reflect differences in the quality and/or location of oil or gas.

Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities. The terminal point is generally regarded as the outlet valve on the lease or field storage tank.

Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date,

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well.

Farmout. An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

Gas. Natural gas.

MBbl. One thousand barrels of oil or other liquid hydrocarbons.

MBOE. One thousand BOE.

Mcf. One thousand cubic feet of gas.

Mcfd. One thousand cubic feet of gas per day

MMcfe. One million cubic feet of gas equivalent.

4

MMBOE. One million BOE.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of gas.

NYMEX. New York Mercantile Exchange.

Oil. Crude oil, condensate, and natural gas liquids.

Operator. The individual or company responsible for the exploration and/or production of an oil or gas well or lease.

Play. A geographic area with hydrocarbon potential.

Polymer. A polymer gel treatment of a well that produces from a water-drive reservoir is intended to reduce excessive water production and increase oil or gas production. Candidate wells are typically produced from naturally fractured carbonate reservoirs such as dolomites and limestone in mature fields. Successful treatments are also run in certain types of sandstone reservoirs. Other practical applications of polymer gels include the treatment of waterflood injection wells to correct channeling or change the injection profile, to improve the ability of the injected fluids to sweep the producing wells in the field, making the waterflood more efficient and allowing the operator to recover more oil in a shorter period of time.

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

The area of the reservoir considered as proved includes all of the following:(i) the area identified by drilling and limited by fluid contacts, if any; and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and gas on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.

Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved reserve additions. The sum of additions to proved reserves from extensions, discoveries, improved recovery, acquisitions, and revisions of previous estimates.

5

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Reserve additions. Changes in proved reserves due to revisions of previous estimates, extensions, discoveries, improved recovery, and other additions and purchases of reserves in-place.

Reserve life. A measure of the productive life of an oil or gas property or a group of properties, expressed in years.

Royalty interest. An interest in an oil and gas lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or operating the wells on the leased acreage. Royalties may be either landowner's royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the leasehold in connection with a transfer to a subsequent owner.

Standardized measure. The present value, discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves in effect as of the dates of such estimates and held constant throughout the productive life of the reserves and deducting the estimated future costs to be incurred in developing, producing, and abandoning the proved reserves (computed based on year-end costs and assuming continuation of existing economic conditions). Future income taxes are calculated by applying the appropriate year-end statutory federal and state income tax rates with consideration of future tax rates already legislated, to pre-tax future net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and gas reserves.

SWD. Salt water disposal well.

Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Waterflood.  A method of secondary recovery in which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells.

Working interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and gas from the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.

References herein to the “Company”, “we”, “us” and “our” mean Tengasco, Inc. or Riley Exploration Permian, Inc.

PART I

ITEM 1.
BUSINESS.

History of the Company

The Company was initially organized in Utah in 1916 under a name later changed to Onasco Companies, Inc.  In 1995, the Company changed its name from Onasco Companies, Inc. by merging into Tengasco, Inc., a Tennessee corporation, formed by the Company solely for that purpose.  On June 11, 2011, the stockholders of the Company approved an Agreement and Plan of Merger which provided for the merger of the Company into a wholly owned subsidiary formed in Delaware for the purpose of changing the Company’s state of incorporation from Tennessee to Delaware resulting in the Company becoming a Delaware corporation.

6

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 Riley. Pursuant to the terms of the Merger Agreement, a business combination between the Registrant and Riley was effected through the merger of Merger Sub with and into Riley, with Riley surviving as the surviving company and as a wholly owned subsidiary of the Registrant (the “Merger” and, collectively with the other transactions described in the Merger Agreement, the “Merger Transaction”). 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, Riley Exploration – Permian, LLC and Riley Permian Operating Company, LLC.

The shares of the Company began trading under the ticker symbol REPX on the NYSE American on March 1, 2021.

OVERVIEW

The Company is in the business of exploration for and production of oil and natural gas.  As of December 31, 2020, the Company’s only areas of operations were in Kansas.  As part of the merger detailed below, the Company’s operations were significantly expanded to the Permian Basin in Texas.  Since the closing of the merger, the Company has pursued potential opportunities in Texas, as well as strategic divestitures of non-core assets in Kansas.  As part of this process, the Company entered into a purchase and sale agreement to sell the legacy Kansas assets. The closing of this divestiture remains subject to various conditions to closing and there can be no assurance that the sale will be completed.  (See Note 15. Subsequent Events included in Notes to Consolidated Financial Statements)

The Company’s wholly owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owned and operated a pipeline which it constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee.  The Company sold all its pipeline assets on August 16, 2013.

The Company’s wholly owned subsidiary, Manufactured Methane Corporation (“MMC”) operated treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas or for the generation of electricity.  The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018.

In connection with the Merger Transaction, the Company acquired the assets of REP, LLC. REP, LLC is an oil and gas exploration and production company with acreage is primarily located on large contiguous blocks in Yoakum County, Texas and Lea, Roosevelt and Chaves Counties in New Mexico; and the offset legacy assets are located in the Permian Basin San Andres fields, which include the Wasson and Brahaney Fields. Unless otherwise noted, the financial and operational data, such as reserves, production, wells and acreage, provided in this document exclude amounts related to REP, LLC’s assets due to the Merger Transaction closing subsequent to December 31, 2020.

General

1. The Kansas Properties

The Company’s operated properties in Kansas are located in central Kansas and as of December 31, 2020 included 153 producing oil wells, 19 shut-in wells, 6 temporarily abandoned wells, and 36 active disposal wells (the “Kansas Properties”).  The Company has onsite production management and field personnel working out of the Hays, Kansas office.

The leases for the Kansas Properties typically provide for a landowner royalty of 12.5%.  Some wells are subject to an overriding royalty interest from approximately 0.5% to 15%.  The Company maintains a 100% working interest in most of its wells in Kansas.

7

During 2020, the Company did not participate in drilling any wells.  However, the Company did sell its interest in six wells during 2020.  By using 3-D seismic evaluation on the Company’s existing leases, the Company has historically added proven direct offset locations.

A.  Kansas Production

The Company’s gross operated oil production in Kansas decreased by 12.2 MBbl from 110.9 MBbl in 2019 to 98.7 MBbl in 2020.  This decrease was primarily due to lower sales volumes on the Veverka D lease as a result of expected declines from higher volumes realized immediately after the polymer work performed in June 2018 and natural declines on various other properties.

B.  Kansas Ten Well Drilling Program

On September 17, 2007, the Company entered into a ten well drilling program with Hoactzin Partners, L.P. (“Hoactzin”), consisting of wells to be drilled on the Company’s Kansas Properties (the “Program”). Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin and of Dolphin Offshore Partners, L.P., the Company’s largest shareholder.  During the 4^th quarter of 2018, the Company acquired Hoactzin’s interest in the Program wells for $131,290.

2.  Tennessee Properties

A.  Manufactured Methane Facilities

On October 24, 2006, the Company signed a twenty-year Landfill Gas Sale and Purchase Agreement (the “Agreement”) with predecessors in interest of Republic Services, Inc. (“Republic”). The Company assigned its interest in the Agreement to MMC.  The Agreement provided that MMC would purchase the entire naturally produced gas stream being collected at the Carter Valley municipal solid waste landfill owned and operated by Republic in Church Hill, Tennessee.  The Company installed a proprietary combination of advanced gas treatment technology to extract the methane component of the purchased gas stream.  (the “Methane Project”).

MMC declared startup of commercial operations of the Methane Project on April 1, 2009.  The total cost for the Methane Project through startup, including pipeline construction, was approximately $4.5 million.

In April 2011, MMC purchased from Parkway Services Group of Lafayette, Louisiana a Caterpillar genset which was delivered in late 2011 and installed at the plant site for generation of electricity.  Total cost of the generator including installation and interconnection with the power grid was approximately $1.1 million.

On January 25, 2012, MMC commenced sales of electricity generated at the Carter Valley site.  The electricity generated was sold under a twenty-year firm price contract with Holston Electric Cooperative, Inc., the local distributor, and Tennessee Valley Authority (“TVA”) through TVA’s Generation Partners program.  That program accepted generated renewable power up to 999KW; MMC’s generation equipment is rated at 974 KW to maximize revenues under the favorable electricity pricing under the Generation Partners program.  The price provision under this contract paid MMC the current retail price charged monthly to small commercial customers by Holston Electric Cooperative, plus a “green” premium of 3 cents per kilowatt hour (KWH) or approximately $.129 per KWH.  Beginning in January 2022 the price paid for electricity will no longer include the three-cent “green” premium component.  A one-eighth royalty on electricity revenues has been paid to the landfill owner.

On September 17, 2007, Hoactzin was conveyed a 75% net profits interest in the Methane Project.  Since the start of 2014, there have been no methane gas sales or revenues and consequently no net profits attributable to Hoactzin’s net profits interest.

On January 26, 2018, the Company closed a sale to Tennessee Renewable Group LLC for all of the Company’s Manufactured Methane assets, except for the applicable U.S. patent, for $2.65 million.  Hoactzin expressly released all claims in future periods against both the Company and Tennessee Renewable Group LLC based on the September 17, 2007 net profits agreement described immediately above.

8

3.  Other Areas of Development

Although focused on development of its current Kansas holdings, the Company will continue to review potential transactions involving producing properties and undeveloped acreage in Kansas as well as acquisition and drilling opportunities in other states including development opportunities on our newly acquired properties in Texas and New Mexico.

Governmental Regulations

The Company is subject to numerous state and federal regulations, environmental and otherwise, that may have a substantial negative effect on its ability to operate at a profit.  For a discussion of the risks involved as a result of such regulations, see, “Effect of Existing or Probable Governmental Regulations on Business” hereinafter in this section, and “The Company has Significant Costs to Conform to Government Regulation of the Oil and Gas Industry” and “The Company has Significant Costs Related to Environmental Matters” included in Item 1A. Risk Factors.

Principal Products or Services and Markets

The principal markets for the Company’s crude oil are local refining companies.  At present, crude oil produced by the Company in Kansas is sold at or near the wells to Coffeyville Resources (“Coffeyville”) in Kansas City, Kansas and to CHS McPherson Refinery (“CHS”) in McPherson, Kansas.  Both Coffeyville and CHS are solely responsible for transportation to their refineries of the oil they purchase.  The Company may sell some or all of its production to one or more additional refineries in order to maximize revenues as oil prices offered by the refineries fluctuate from time to time.

Drilling Equipment

The Company does not own a drilling rig or any related drilling equipment.  The Company obtains drilling services as required from time to time from various drilling contractors.

Distribution Methods of Products or Services

Crude oil is normally delivered to refineries in Kansas by tank truck.

Competitive Business Conditions, Competitive Position in the Industry and Methods of Competition

The Company’s contemplated oil and gas exploration activities in the State of Kansas or other states will be undertaken in a highly competitive and speculative business atmosphere.  In seeking any other suitable oil and gas properties for acquisition, the Company will be competing with a number of other companies, including large oil and gas companies and other independent operators with greater financial resources.  As of December 31, 2020, management did not believe that the Company’s competitive position in the oil and gas industry was significant as the Company existed at that time.

There are numerous producers in the area of the Kansas Properties.  Some of these companies are larger than the Company and have greater financial resources.  These companies are in competition with the Company for lease positions in the known producing areas in which the Company currently operates, as well as other potential areas of interest.

Although management does not foresee any difficulties in procuring contracted drilling rigs, several factors, including increased competition in the area, may limit the availability of drilling rigs, rig operators and related personnel and/or equipment in the future. Such limitations would have a natural adverse impact on the profitability of the Company’s operations.

The Company anticipates no difficulty in procuring well drilling permits in any state.  The Company generally does not apply for a permit until it is actually ready to commence drilling operations.

The prices of the Company’s products are controlled by the world oil market.  Thus, competitive pricing behaviors are considered unlikely; however, competition in the oil and gas exploration industry exists in the form of competition to acquire the most promising acreage blocks and obtaining the most favorable process for transporting the product.

Sources and Availability of Raw Materials

Excluding the development of oil and gas reserves and the production of oil and gas, the Company’s operations are not dependent on the acquisition of any raw materials.

9

Dependence on One or a Few Major Customers

At present, crude oil from the Kansas Properties is being purchased at the well and trucked by Coffeyville and CHS, which are responsible for transportation of the crude oil purchased.  The Company may sell some or all of its production to one or more additional refineries in order to maximize revenues as oil prices offered by the refineries fluctuate from time to time.

Patents, Trademarks, Licenses, Franchises, Concessions, Royalty Agreements or Labor Contracts, Including Duration

On October 19, 2010, the Company’s subsidiary MMC was granted United States Patent No. 7,815,713 for Landfill Gas Purification Method and System, pursuant to application filed January 10, 2007.  The patent term is for twenty years from filing date plus adjustment period of 595 days due to the length of the review process resulting in grant of the patent.  The patent is for the process designed and utilized by MMC at the Carter Valley landfill facility.  The patent may result in a competitive advantage to MMC in seeking new projects, and in the receipt of licensing fees for other projects that may be using or wish to use the process in the future.  However, the limited number of high Btu projects currently existing and operated by others, the variety of processes available for use in high Btu projects, and the effects of current gas markets and decreasing or inapplicable green energy incentives for such projects in combination cause the materiality of any licensing opportunity presented by the patent to be difficult to determine or estimate, and thus the licensing fees from the patent, if any are received, may not be material to the Company’s overall results of operations.

Need For Governmental Approval of Principal Products or Services

None of the principal products offered by the Company require governmental approval, although permits are required for drilling oil or gas wells.

Effect of Existing or Probable Governmental Regulations on Business

Exploration and production activities relating to oil and gas leases are subject to numerous environmental laws, rules and regulations.  The Federal Clean Water Act requires the Company to construct a fresh water containment barrier between the surface of each drilling site and the underlying water table.  This involves the insertion of steel casing into each well, with cement on the outside of the casing.  The Company has fully complied with this environmental regulation.

As part of the Company’s purchase of the Kansas Properties, the Company acquired a statewide permit to drill in Kansas.  Applications under such permit are applied for and issued within one to two weeks prior to drilling.  At the present time, the State of Kansas does not require the posting of a bond either for permitting or to ensure that the Company’s wells are properly plugged when abandoned.  All of the wells in the Kansas Properties have all permits required and the Company believes that it is in compliance with the laws of the State of Kansas.

The Company’s exploration, production and marketing operations are regulated extensively at the federal, state and local levels.  The Company has made and will continue to make expenditures in its efforts to comply with the requirements of environmental and other regulations.  Further, the oil and gas regulatory environment could change in ways that might substantially increase these costs. These regulations affect the Company’s operations and limit the quantity of hydrocarbons it may produce and sell.  Other regulated matters include marketing, pricing, transportation and valuation of royalty payments.  The Company’s operations are also subject to numerous and frequently changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.  For example, in May 2014 the Company become subject to regulations under the federal Endangered Species Act relating to the protection of the lesser prairie chicken as a threatened species.  To avoid stringent penalties for violation of those regulations, the Company entered into a state-operated voluntary agreement, which allowed the Company to avoid those penalties, provided certain protective methods are followed in drilling operations and remediation fees are paid by the Company for any wells determined to be likely to interfere with the habitat of the threatened species.  These fees may increase the Company’s costs to drill in Kansas by approximately $40,000 per well.  The Company owns or leases, and has in the past owned or leased, properties that have been used for the exploration and production of oil and gas and these properties and the wastes disposed on these properties may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, the Oil Pollution Act of 1990, the Resource Conservation and Recovery Act, the Federal Water Pollution Control Act and analogous state laws.  Under such laws, the Company could be required to remove or remediate previously released wastes or property contamination.

Laws and regulations protecting the environment have generally become more stringent and, may in some cases, impose “strict liability” for environmental damage.  Strict liability means that the Company may be held liable for damage without regard to whether it was negligent or otherwise at fault.  Environmental laws and regulations may expose the Company to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed.  Failure to comply with these laws and regulations may result in the imposition of administrative, civil and criminal penalties.

10

While management believes that the Company’s operations are in substantial compliance with existing requirements of governmental bodies, the Company’s ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls.  The Company’s current permits and authorizations and ability to get future permits and authorizations may be susceptible, on a going forward basis, to increased scrutiny, greater complexity resulting in increased costs or delays in receiving appropriate authorizations.

The Company maintains an Environmental Response Policy and Emergency Action Response Policy Program.  A plan was adopted which provides for the erection of signs at each well containing telephone numbers of the Company’s office.  A list is maintained at the Company’s office and at the home of key personnel listing phone numbers for fire, police, emergency services and Company employees who will be needed to deal with emergencies.

The foregoing is only a brief summary of some of the existing environmental laws, rules, and regulations to which the Company’s business operations are subject, and there are many others, the effects of which could have an adverse impact on the Company.  Future legislation in this area will be enacted and revisions will be made in current laws.  No assurance can be given as to the effect these present and future laws, rules, and regulations will have on the Company’s current and future operations.

Research and Development

None.

Human Capital Management

The Company is committed to delivering strong financial results in a safe, environmentally and socially responsible manner.  This commitment relies on the expertise and positive contributions of all of our personnel.

As of December 31, 2020, the Company had twelve (12) full-time employees. These employees were located in Colorado, Kansas, and Texas.  In addition to our full-time employees, the Company also relies on services provided by independent contractors who assist our full-time staff in a range of areas including geology, engineering, land, accounting, and field operations, as needed. As of the date of this filing, the Company has fifty-eight (58) employees representing a significant increase in personnel as part of the merger.

The Company has focused its efforts on the following areas as part of our commitment to attract, retain and develop our personnel:

• Training:  We provide our personnel with workplace safety training and guidance, as well as resources necessary to comply with safety rules and regulations.

• Compensation and Benefits: One element of our efforts to attract and retain our personnel is our commitment to competitive compensation and benefits packages, including annual bonuses; a 401(k) savings plan; stock awards; medical, dental and vision health care coverage; health savings and dependent-care flexible spending accounts; among other benefits.

• Inclusion and Diversity: The diverse backgrounds and experiences of our personnel contributes to the wide range of perspectives that lead to well-rounded operations. Our management is focused on proactively increasing diversity and inclusion awareness, as well as identify challenges and areas in need of improvement or enhancement.

COVID – 19

The COVID-19 team has developed and implemented a number of safety measures, which have successfully kept our workforce healthy and safe. The COVID-19 team 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. Other measures have included closing our office buildings and locations to the public, implementing social distancing and encouraging employees to work from home.

11

In response to the COVID-19 pandemic, the Company began providing the following benefits to its employees:

● covering the cost of COVID-19 testing through expanded insurance coverage;

● promoting telehealth benefits;

● promoting mental health and well-being plans;

● providing additional paid sick leave for quarantined employees.

Available Information

The Company is a reporting company, as that term is defined under the Securities Acts, and therefore files reports, including Quarterly Reports on Form 10-Q and Annual Reports on Form 10-K such as this Report, proxy information statements and other materials with the Securities and Exchange Commission (“SEC”).  You may read and copy any materials the Company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington D.C. 20549 upon payment of the prescribed fees.  You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

In addition, the Company is an electronic filer and files its Reports and information with the SEC through the SEC’s Electronic Data Gathering, Analysis and Retrieval system (“EDGAR”).  The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically through EDGAR with the SEC, including all of the Company’s filings with the SEC.  These may be read and printed without charge from the SEC’s website.  The address of that site is www.sec.gov.

The Company’s website is located at www.rileypermian.com.  On the home page of the website, you may access, free of charge, the Company’s Annual Report on Form 10-K. Under the Investor Information, SEC Filings tab you will find the Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Section 16 filings (Form 3, 4 and 5) and any amendments to those reports as reasonably practicable after the Company electronically files such reports with the SEC.  The information contained on the Company’s website is not part of this Report or any other report filed with the SEC.

ITEM 1A.
RISK FACTORS

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating the Company’s business and future prospects.  The risk factors described below are not exhaustive and you are encouraged to perform your own investigation with respect to the Company and its business.  You should also read the other information included in this Form 10-K, including the financial statements and related notes.

The Company’s indebtedness, global recessions, or disruption in the domestic and global financial markets could have an adverse effect on the Company’s operating results and financial condition.

As of December 31, 2020, the Company had no outstanding principal amount of indebtedness under its credit facility with Prosperity Bank.  Upon closing the Merger Transaction with Riley on February 26, 2021, the credit facility with Prosperity Bank was terminated.  Although the Company had no bank indebtedness as of February 26, 2021, should it enter into a new credit facility and experience an increased level of indebtedness, coupled with domestic and global economic conditions, the associated volatility of energy prices, and the levels of disruption and continuing relative illiquidity in the credit markets may, if continued for an extended period, have several important and adverse consequences on the Company’s business and operations.  For example, any one or more of these factors could (i) make it difficult for the Company to service or refinance its indebtedness; (ii) increase the Company’s vulnerability to additional adverse changes in economic and industry conditions; (iii) require the Company to dedicate a substantial portion or all of its cash flow from operations and proceeds of any debt or equity issuances or asset sales to pay or provide for its indebtedness; (iv) limit the Company’s ability to respond to changes in our businesses and the markets in which we operate; (v) place the Company at a disadvantage to our competitors that are not as highly leveraged; or (vi) limit the Company’s ability to borrow money or raise equity to fund our working capital, capital expenditures, acquisitions, debt service requirements, investments, general corporate activity or other financing needs.  The Company continues to closely monitor the global financial and credit markets, as well as the significant volatility in the market prices for oil and natural gas.  As these events unfold, the Company will continue to evaluate and respond to any impact on Company operations.  The Company has and will continue to adjust its drilling plans and capital expenditures as necessary.  However, external financing in the capital markets may not be readily available, and without adequate capital resources, the Company’s drilling and other activities may be limited and the Company’s business, financial condition and results of operations may suffer.  Additionally, in light of the credit markets and the volatility in pricing for oil and natural gas, the Company’s ability to enter into future beneficial relationships with third parties for exploration and production activities may be limited, and as a result, may have an adverse effect on current operational strategy and related business initiatives.

12

Agreements Governing the Company’s Indebtedness may Limit the Company’s Ability to Execute Capital Spending or to Respond to Other Initiatives or Opportunities as they May Arise.

The availability of borrowings by the Company under the terms of virtually all reserve-based energy loans is subject to an upper limit of the borrowing base as determined by the lender’s calculated estimated future cash flows from the Company’s oil and natural gas reserves, the Company expects any decline in the pricing for these commodities, if continued for any extended period, would very likely result in a reduction in the Company’s borrowing base.  A reduction in the Company’s borrowing base could be significant and as a result, would not only reduce the capital available to the Company but may also require repayment of principal to the lender under the terms of the facility. Additionally, the terms of the Company’s amended and restated credit facility with Prosperity Bank restrict the Company’s ability to incur additional debt.  The credit facility contains covenants and other restrictions customary for oil and gas borrowing base credit facilities, including limitations on debt, liens, and dividends, voluntary redemptions of debt, investments, and asset sales.  In addition, the credit facility requires that the Company maintain compliance with certain financial tests and financial covenants.  If future debt financing is not available to the Company when required as a result of limited access to the credit markets or otherwise, or is not available on acceptable terms, the Company may be unable to invest needed capital for drilling and exploration activities, take advantage of business opportunities, respond to competitive pressures or refinance maturing debt.  In addition, the Company may be forced to sell some of the Company’s assets on an untimely basis or under unfavorable terms.  Any of these results could have a material adverse effect on the Company’s operating results and financial condition.

The Company’s Borrowing Base under a Credit Facility May be Reduced by the Lender.

Upon closing the Merger Transaction with Riley on February 26, 2021, the Company’s credit facility with Prosperity Bank was terminated.

The borrowing base under virtually all revolving credit facilities under a reserve-based loan will be determined from time to time by the lender, consistent with its customary natural gas and crude oil lending practices.   Reductions in estimates 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 lender’s practices regarding estimation of reserves.  If either cash flow from operations or the Company’s borrowing base decreases 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 production may be limited.  In addition, these adverse conditions could lead to non-compliance with certain credit facility covenants, ultimately causing the Company to default under its revolving credit facility.

The Company’s Credit Facility is Subject to Variable Rates of Interest and Contains Certain Financial Covenants Which Could Negatively Impact the Company.

Upon closing the Merger Transaction with Riley on February 26, 2021, the Company’s credit facility with Prosperity Bank was terminated.

Borrowings under the Company’s credit facility with Prosperity Bank are at variable rates of interest and expose the Company to interest rate risk.  If interest rates increase, the Company’s debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and the Company’s income and cash flows would decrease.  The Company’s credit facility agreement contains certain financial covenants based on the Company’s performance.  If the Company’s financial performance results in any of these covenants being violated, Prosperity Bank may choose to require repayment of any outstanding borrowings sooner than currently required by the agreement.

13

Declines in Oil or Gas Prices Have and Will Materially Adversely Affect the Company’s Revenues.

The Company’s financial condition and results of operations depend in large part upon the prices obtainable for the Company’s oil and natural gas production and the costs of finding, acquiring, developing and producing reserves.  As seen in recent years, prices for oil and natural gas are subject to extreme fluctuations in response to changes in supply, market uncertainty and a variety of additional factors that are beyond the Company’s control.  These factors include worldwide political instability (especially in the Middle East and other oil producing regions), the foreign supply of oil and gas, the price of foreign imports, the level of drilling activity, the level of consumer product demand, government regulations and taxes, the price and availability of alternative fuels, speculating activities in the commodities markets, impact of the recent COVID-19 pandemic, and the overall economic environment.  The Company’s operations are substantially adversely impacted as oil prices decline.  Lower prices dramatically affect the Company’s revenues from its drilling operations.  Further, drilling of new wells, development of the Company’s leases and acquisitions of new properties are also adversely affected and limited.   As a result, the Company’s potential revenues from operations as well as the Company’s proved reserves may substantially decrease from levels achieved during the period when oil prices were much higher.  There can be no assurances as to the future prices of oil or gas.  A substantial or extended decline in oil or gas prices would have a material adverse effect on the Company’s financial position, results of operations, quantities of oil and gas that may be economically produced, and access to capital.  Oil and natural gas prices have historically been and are likely to continue to be volatile.

This volatility makes it difficult to estimate with precision the value of producing properties in acquisitions and to budget and project the return on exploration and development projects involving the Company’s oil and gas properties.  In addition, unusually volatile prices often disrupt the market for oil and gas properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties.

Risk in Rates of Oil and Gas Production, Development Expenditures, and Cash Flows May Have a Substantial Impact on the Company’s Finances.

Projecting the effects of commodity prices on production, and timing of development expenditures include many factors beyond the Company’s control.  The future estimates of net cash flows from the Company’s proved and other reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time.  Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates, which would have a significant impact on the Company’s financial position.

The Company Has a History of Significant Losses.

During the early stages of the development of its oil and gas business, the Company had a history of significant losses from operations, in particular its development of the Swan Creek Field in Tennessee and the Company’s related pipeline assets.  In addition, the Company has recorded an impairment of its oil and gas properties during 2008, 2015, 2016, and 2020, impairments of its pipeline assets during 2010 and 2012, and an impairment of its methane facility in 2014.  As of December 31, 2020, the Company has an accumulated deficit of $55.6 million.  The Company recorded net losses of $2.0 million in 2009, $1.7 million in 2010, $0.1 million in 2012, $0.8 million in 2014, $24.7 million in 2015, $4.2 million in 2016, $0.6 million in 2017, $0.5 million in 2019, and $3.6 million in 2020.  In the event the Company experiences losses in the future, those losses may curtail the Company’s development and operating activities, and may require the Company to take certain actions in order to remain in compliance the NYSE American listing standards.

The Company’s Oil and Gas Operations Involve Substantial Cost and are Subject to Various Economic Risks.

The Company’s oil and gas operations are subject to the economic risks typically associated with exploration, development, and production activities, including the necessity of making significant expenditures to locate or acquire new producing properties or to drill exploratory and developmental wells.  In conducting exploration and development activities, the presence of unanticipated pressure or irregularities in formations, miscalculations, and accidents may cause the Company’s exploration, development, and production activities to be unsuccessful.  This could result in a total loss of the Company’s investment in such well(s) or property.  In addition, the cost of drilling, completing and operating wells is often uncertain.

The Company’s Failure to Find or Acquire Additional Reserves Will Result in the Decline of the Company’s Reserves Materially From Their Current Levels.

The rate of production from the Company’s Kansas oil properties generally declines as reserves are depleted.  Except to the extent that the Company either acquires additional properties containing proved reserves, conducts successful exploration and development drilling, or successfully applies new technologies or identifies additional behind-pipe zones or secondary recovery reserves, the Company’s proved reserves will decline materially as production from these properties continues.  The Company’s future oil and natural gas production is consequently highly dependent upon the level of success in acquiring or finding additional reserves or other alternative sources of production.  Any decline in oil prices and any prolonged period of lower prices will adversely impact the Company’s future reserves since the Company is less likely to acquire additional producing properties during such periods.  The lower oil prices may have a negative effect on new drilling and development as such activities become far less likely to be profitable.  Thus, any acquisition of new properties poses a greater risk to the Company’s financial conditions as such acquisitions may be commercially unreasonable.

14

In addition, the Company’s drilling for oil and natural gas may involve unprofitable efforts not only from dry wells but also from wells that are productive but do not produce sufficient volumes to be commercially profitable after deducting drilling, operating, and other costs.  Also, wells that are profitable may not achieve a targeted rate of return.  The Company relies on seismic data and other technologies in identifying prospects and in conducting exploration activities.  The seismic data and other technologies used do not allow the Company to know conclusively prior to drilling a well whether oil or natural gas is present or may be produced economically.

The ultimate costs of drilling, completing, and operating a well can adversely affect the economics of a project.  Further drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including unexpected drilling conditions, title problems, pressure or irregularities in formations, equipment failures, accidents, adverse weather conditions, environmental and other governmental requirements, and the cost of, or shortages or delays in the availability of drilling rigs, equipment, and services.

The Company’s Reserve Estimates May Be Subject to Other Material Downward Revisions.

The Company’s oil and natural gas reserve estimates may be subject to material downward revisions for additional reasons other than the factors mentioned in the previous risk factor entitled “The Company’s Failure to Find or Acquire Additional Reserves Will Result in the Decline of the Company’s Reserves Materially From Their Current Levels.”  While the future estimates of net cash flows from the Company’s proved reserves and their present value are based upon assumptions about future production levels, prices, and costs that may prove to be incorrect over time, those same assumptions, whether or not they prove to be correct, may cause the Company to make drilling or developmental decisions that will result in some or all of the Company’s proved reserves to be removed from time to time from the proved reserve categories previously reported by the Company.

This may occur because economic expectations or forecasts, together with the Company’s limited resources, may cause the Company to determine that drilling or development of certain of its properties may be delayed or may not foreseeably occur, and as a result of such decisions any category of proved reserves relating to those yet undrilled or undeveloped properties may be removed from the Company’s reported proved reserves.  Consequently, the Company’s proved reserves of oil may be materially revised downward from time to time.

In addition, the Company may elect to sell some or all of its oil or gas reserves in the normal course of the Company’s business.  Any such sale would result in all categories of those proved oil or gas reserves that were sold no longer being reported by the Company.

There is Risk That the Company May Be Required to Write Down the Carrying Value of its Natural Gas and Crude Oil Properties.

The Company uses the full cost method to account for its natural gas and crude oil operations.  Accordingly, the Company capitalizes the cost to acquire, explore for, and develop natural gas and crude oil properties.  Under full cost accounting rules, the net capitalized cost of natural gas and crude oil properties and related deferred income tax if any may not exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%, plus cost of properties not being amortized and the lower of cost or estimated fair value of unproven properties included in the cost being amortized.  If net capitalized cost of natural gas and crude oil properties exceeds the ceiling limit, the Company must charge the amount of the excess, net of any tax effects, to earnings.  This charge does not impact cash flow from operating activities but does reduce the Company’s stockholders’ equity and earnings.  The risk that the Company will be required to write-down the carrying value of natural gas and crude oil properties increases when natural gas and crude oil prices are low.  In addition, write-downs may occur if the Company experiences substantial downward adjustments to its estimated proved reserves.  An expense recorded in a period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling applicable to the subsequent period.

Due to the low oil prices experienced in the quarter ended December 31, 2014 and during 2015, the Company experienced ceiling test failures during 2015 resulting in recording non-cash impairments of $14.5 million.  During 2016, the Company recorded ceiling test failures resulting in recording non-cash impairment of $2.7 million.  During 2020, the Company recorded ceiling test failures resulting in recording non-cash impairment of $0.9 million.   Should the Company experience prices at depressed levels for an extended amount of time during future periods, the Company may be required to record additional impairment of its oil properties.

15

Use of the Company’s Net Operating Loss Carryforwards May Be Limited.

At December 31, 2020, the Company 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.  Most of these loss carryforwards will eventually expire if not utilized.  In addition, as to a portion of the U.S. net operating loss carryforwards, the amount of such carryforwards that the Company can use annually is limited under U.S. tax laws.  Uncertainties exist as to both the calculation of the appropriate deferred tax assets based upon the existence of these loss carryforwards, as well as the future utilization of the operating loss carryforwards under the criteria set forth under FASB ASC 740, Income Taxes. In addition, limitations exist upon use of these carryforwards in the event that a change in control of the Company occurs, such as the Merger Transaction with Riley on February 26, 2021.  There are risks that the Company may not be able to utilize some or all of the remaining carryforwards, or that deferred tax assets that were previously booked based upon such carryforwards may be written down or reversed based on future economic factors that may be experienced by the Company.  The effect of such write downs or reversals, if they occur, may be material and substantially adverse.  At December 31, 2020, federal net operating loss carryforwards amounted to approximately $35.4 million, of which $30.1 million expires between 2021 and 2037 which can offset 100% of taxable income and $5.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The Company recorded an allowance on the deferred tax asset at December 31, 2020 primarily due to expected future losses in the near term which would cause cumulative losses being incurred during the 3 year period.  The total valuation allowance at December 31, 2020 was $11.1 million and $10.7 million at December 31, 2019.  The net operating loss information above does not include the impact of the Merger Transaction with Riley.

Shortages of Oil Field Equipment, Services or Qualified Personnel Could Adversely Affect the Company’s Results of Operations.

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 and natural gas prices, causing periodic shortages.  The Company does not own any drilling rigs and is dependent upon third parties to obtain and provide such equipment as needed for the Company’s drilling activities.  There have also been shortages of drilling rigs and other equipment when oil prices have risen.  As prices increased, the demand for rigs and equipment increased along with the number of wells being drilled.  These factors also cause significant increases in costs for equipment, services and personnel.  These shortages or price increases could adversely affect the Company’s profit margin, cash flow, and operating results or restrict the Company’s ability to drill wells and conduct ordinary operations.

The Company has Significant Costs to Conform to Government Regulation of the Oil and Gas Industry.

The Company’s exploration, production, and marketing operations are regulated extensively at the federal, state, and local levels.  The Company is currently in compliance with these regulations.  In order to maintain its compliance, the Company has made and will continue to make substantial expenditures in its efforts to comply with the requirements of environmental and other regulations.  Further, the oil and gas regulatory environment could change in ways that might substantially increase these costs.  Hydrocarbon-producing states regulate conservation practices and the protection of correlative rights.  These regulations affect the Company’s operations and limit the quantity of hydrocarbons it may produce and sell.  Other regulated matters include marketing, pricing, transportation, and valuation of royalty payments.

The Company has Significant Costs Related to Environmental Matters.

The Company’s operations are also subject to numerous and frequently changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.  The Company owns or leases, and has owned or leased, properties that have been leased for the exploration and production of oil and gas and these properties and the wastes disposed on these properties may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, the Oil Pollution Act of 1990, the Resource Conservation and Recovery Act, the Federal Water Pollution Control Act, the federal Endangered Species Act, and similar state laws.  Under such laws, the Company could be required to remove or remediate wastes or property contamination.

Laws and regulations protecting the environment have generally become more stringent and, may in some cases, impose “strict liability” for environmental damage.  Strict liability means that the Company may be held liable for damage without regard to whether it was negligent or otherwise at fault.  Environmental laws and regulations may expose the Company to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed.  Failure to comply with these laws and regulations may result in the imposition of administrative, civil, and criminal penalties.

16

The Company’s ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls.  The Company’s current permits and authorizations and ability to get future permits and authorizations may be susceptible, on a going forward basis, to increased scrutiny and greater complexity resulting in increased cost or delays in receiving appropriate authorizations.

Concerns About Climate Change and Related Regulatory, Social and Market Actions May Adversely Affect Our Business

Continuing and increasing political and social attention to the issue of climate change has resulted in legislative, regulatory and other initiatives, including international agreements, to reduce greenhouse gas emissions, such as carbon dioxide and methane. Policy makers and regulators at both the U.S. federal and state levels have already imposed, or stated intentions to impose, laws and regulations designed to quantify and limit the emission of greenhouse gases. For example, both the EPA and the BLM have issued regulations for the control of methane emissions, which also include leak detection and repair requirements, for the oil and gas industry; although the methane specific requirements of some of these regulations have been repealed, similar or more stringent emissions requirements may be imposed by the Biden Administration. In addition, several states where we operate, including Texas and New Mexico202, have already imposed, or stated intentions to impose, laws or regulations designed to reduce methane emissions from oil and gas exploration and production activities. With respect to more comprehensive regulation, policy makers and political leaders have made, or expressed support for, a variety of proposals, such as the development of cap-and-trade or carbon tax programs. In addition, President Biden has highlighted addressing climate change as a priority of his administration, and he previously released an energy plan calling for a number of sweeping changes to address climate change, including, among other measures, a national mobilization effort to achieve net-zero emissions for the U.S. economy by 2050, through increased use of renewable power, stricter fuel-efficiency standards and support for zero-emission vehicles. President Biden issued a number of executive orders in January 2021 with the purpose of implementing certain of these changes, including the rejoining of the Paris Agreement, a call for the issuance of more stringent methane emissions regulations for oil and gas facilities and an order directing federal agencies to procure electric vehicles. Although the full impact of these orders is uncertain at this time, the adoption and implementation of these or other initiatives may result in the restriction or cancellation of oil and natural gas activities, greater costs of compliance or consumption (thereby reducing demand for our products) or an impairment in our ability to continue our operations in an economic manner.

In addition to regulatory risk, other market and social initiatives resulting from the changing perception of climate change present risks for our business. For example, in an effort to promote a lower-carbon economy, there are various public and private initiatives subsidizing the development and adoption of alternative energy sources and technologies, including by mandating the use of specific fuels or technologies. These initiatives may reduce the competitiveness of carbon-based fuels, such as oil and gas. Moreover, an increasing number of financial institutions, funds and other sources of capital have begun restricting or eliminating their investment in oil and natural gas activities due to their concern regarding climate change. Such restrictions in capital could decrease the value of our business and make it more difficult to fund our operations. Finally, governmental entities and other plaintiffs have brought, and may continue to bring, claims against us and other oil and gas companies for purported damages caused by the alleged effects of climate change. These and the other regulatory, social and market risks relating to climate change described above could result in unexpected costs, increase our operating expense and reduce the demand for our products, which in turn could lower the value of our reserves and have an adverse effect on our profitability, financial condition and liquidity.

Insurance Does Not Cover All Risks.

Exploration for and development and production of oil can be hazardous, involving unforeseen occurrences such as blowouts, fires, and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life or damage to property or the environment.  Although the Company maintains insurance against certain losses or liabilities arising from its operations in accordance with customary industry practices and in amounts that management believes to be prudent, insurance is not available to the Company against all operational risks.

The Company’s Methane Extraction Operation from Non-conventional Reserves Involves Substantial Costs and is Subject to Various Economic, Operational, and Regulatory Risks.

The Company’s operations in any future project involving the extraction of methane gas from non-conventional reserves such as landfill gas streams, would require investment of substantial capital and is subject to the risks typically associated with capital intensive operations, including risks associated with the availability of financing for required equipment, construction schedules, air and water environmental permitting, and locating transportation facilities and customers for the products produced from those operations which may delay or prevent startup of such projects.  After startup of commercial operations, the presence of unanticipated pressures or irregularities in constituents of the raw materials used in such projects from time to time, miscalculations or accidents may cause the Company’s project activities to be unsuccessful.  Although the technologies to be utilized in such projects are believed to be effective and economical, there are operational risks in the use of such technologies in the combination to be utilized by the Company as a result of both the combination of technologies and the early stages of commercial development and use of such technologies for methane extraction from non-conventional sources such as those to be used by the Company.  This risk could result in total or partial loss of the Company’s investment in such projects.  The economic risks of such projects include the marketing risks resulting from price volatility of the methane gas produced from such projects, which is similar to the price volatility of natural gas.

17

We have been granted one U.S. patent and have been granted a continuation patent application relating to certain aspects of our methane extraction technology.  Our ability to license our technology is substantially dependent on the validity and enforcement of this patent.  We cannot assure you that our patent will not be invalidated, circumvented, or challenged, or that the rights granted under the patents will provide us competitive advantages.  In addition, third parties may seek to challenge, invalidate, circumvent, or render unenforceable any patents or proprietary rights owned by or licensed to us based on, among other things: subsequently discovered prior art; lack of entitlement to the priority of an earlier, related application; or failure to comply with the written description, best mode, enablement, or other applicable requirements. If a third party is successful in challenging the validity of our patent, our inability to enforce our intellectual property rights could materially harm our methane extraction business.  Furthermore, our technology may be the subject of claims of intellectual property infringement in the future.  Our technology may not be able to withstand third-party claims or rights against their use.

Any intellectual property claims, with or without merit, could be time-consuming, expensive to litigate or settle, could divert resources and attention and could require us to obtain a license to use the intellectual property of third parties.  We may be unable to obtain licenses from these third parties on favorable terms, if at all.  Even if a license is available, we may have to pay substantial royalties to obtain a license.  If we cannot defend such claims or obtain necessary licenses on reasonable terms, we may be precluded from offering most or all of our technology and our methane extraction business may be adversely affected.

The Company Faces Significant Competition with Respect to Acquisitions or Personnel.

The oil and gas business is highly competitive.  In seeking any suitable oil and gas properties for acquisition, or drilling rig operators and related personnel and equipment, the Company may not be able to compete with most other companies, including large oil and gas companies and other independent operators with greater financial and technical resources and longer history and experience in property acquisition and operation.

The Company Depends on Key Personnel, Whom it May Not be Able to Retain or Recruit.

Certain members of present management and certain Company employees have substantial expertise in the areas of endeavor presently conducted and to be engaged in by the Company.  To the extent that their services become unavailable, the Company would be required to retain other and additional qualified personnel to perform these services in technical areas upon which the Company is dependent to conduct exploration and production activities.  The Company does not know whether it would be able to recruit and hire qualified and additional persons upon acceptable terms.  The Company does not maintain “Key Person” insurance for any of the Company’s key employees.

The Company’s Operations are Subject to Changes in the General Economic Conditions.

Virtually all of the Company’s operations are subject to the risks and uncertainties of adverse changes in general economic conditions, the outcome of potential legal or regulatory proceedings, changes in environmental, tax, labor and other laws and regulations to which the Company is subject, and the condition of the capital markets utilized by the Company to finance its operations.

Being a Public Company Significantly Increases the Company’s Administrative Costs.

The Sarbanes-Oxley Act of 2002, as well as rules subsequently implemented by the SEC and listing requirements subsequently adopted by the NYSE American, the exchange on which the Company’s stock is traded, in response to Sarbanes-Oxley, have required changes in corporate governance practices, internal control policies and audit committee practices of public companies.  Although the Company is a relatively small public company, these rules, regulations, and requirements for the most part apply to the same extent as they apply to all major publicly traded companies. As a result, they have significantly increased the Company’s legal, financial, compliance, and administrative costs, and have made certain other activities more time consuming and costly, as well as requiring substantial time and attention of our senior management.  The Company expects its continued compliance with these and future rules and regulations to continue to require significant resources.  These rules and regulations also may make it more difficult and more expensive for the Company to obtain director and officer liability insurance in the future, and could make it more difficult for it to attract and retain qualified members for the Company’s Board of Directors, particularly to serve on its audit committee.

18

We May Fail to Realize the Anticipated Benefits of the Merger

The ultimate success of the Merger Transaction will depend on, among other things, our ability to combine the legacy Company business with REP, LLC’s businesses in a manner that realizes anticipated synergies and benefits. If we are not able to successfully achieve these synergies, or the cost to achieve these synergies is greater than expected, then the anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. It is possible that the integration process could result in the loss of key employees, the loss of customers, the disruption of our ongoing businesses, inconsistencies in standards, controls, procedures and policies, unexpected integration issues, higher than expected integration costs and an overall post‑completion integration process that takes longer than originally anticipated. Furthermore, our board of directors and management team consist of directors and employees from each of the legacy companies and two independent directors. The integration of these individuals could require the reconciliation of differing priorities and strategic philosophies, which may not be successful or take longer than anticipated.

Shares Eligible for Future Sale May Depress the Company’s Stock Price.

At December 31, 2020, the Company had approximately 890,420 shares of common stock outstanding of which approximately 458,368 shares were held by officers, directors, and affiliates.  In addition, options to purchase 104 shares of unissued common stock were granted under the Tengasco, Inc. Stock Incentive Plan all of which were vested at December 31, 2020.  These options expired on January 3, 2021.  These share counts have been adjusted for the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.

All of the shares of common stock held by affiliates are restricted or controlled securities under Rule 144 promulgated under the Securities Act of 1933, as amended (the “Securities Act”).  The shares of the common stock issuable upon exercise of the stock options have been registered under the Securities Act.  Sales of shares of common stock under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of the common stock and could impair the Company’s ability to raise additional capital through the sale of equity securities.

Future Issuance of Additional Shares of the Company’s Common Stock Would Cause Dilution of Ownership Interest and Adversely Affect Stock Price.

The Company may in the future issue previously authorized and unissued securities, resulting in the dilution of the ownership interest of its current stockholders.  The Company is currently authorized to issue a total of 100 million shares of common stock with such rights as determined by the Board of Directors.  Of that amount, approximately 0.9 million shares have been issued (this share count has been adjusted for the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021). The potential issuance of the approximately 99.1 million remaining authorized but unissued shares of common stock may create downward pressure on the trading price of the Company’s common stock.

The Company may also issue additional shares of its common stock or other securities that are convertible into or exercisable for common stock for raising capital or other business purposes.  Future sales of substantial amounts of common stock, or the perception that sales could occur, could have a material adverse effect on the price of the Company’s common stock.

Cyber Attacks May Adversely Impact Our Operations

Our business has become increasingly dependent on digital technologies, and we anticipate expanding the use of these technologies in our operations, including through artificial intelligence, process automation and data analytics. Concurrent with the growing dependence on technology is greater sensitivity to cyber attack related activities, which have increasingly targeted our industry. Cyber attackers often attempt to gain unauthorized access to digital systems for purposes of misappropriating confidential and proprietary information, intellectual property or financial assets, corrupting data or causing operational disruptions as well as preventing users from accessing systems or information for the purpose of demanding payment in order for users to regain access. These attacks may be perpetrated by third parties or insiders. Techniques used in these attacks often range from highly sophisticated efforts to electronically circumvent network security to more traditional intelligence gathering and social engineering aimed at obtaining information necessary to gain access. Cyber attacks may also be performed in a manner that does not require gaining unauthorized access, such as by causing denial-of-service attacks. In addition, our vendors, midstream providers and other business partners may separately suffer disruptions or breaches from cyber attacks, which, in turn, could adversely impact our operations and compromise our information. Although we have not suffered material losses related to cyber attacks to date, if we were successfully attacked, we could incur substantial remediation and other costs or suffer other negative consequences, including litigation risks. Moreover, as the sophistication of cyber attacks continues to evolve, we may be required to expend significant additional resources to further enhance our digital security or to remediate vulnerabilities.

19

The Company May Issue Shares of Preferred Stock with Greater Rights than Common Stock.

Subject to the rules of the NYSE American, the Company’s charter authorizes the Board of Directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from holders of the Company’s common stock.  Any preferred stock that is issued may rank ahead of the Company’s common stock in terms of dividends, priority, and liquidation premiums and may have greater voting rights than the Company’s common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES.

Property Location, Facilities, Size and Nature of Ownership.

Following the closing of the Merger Transaction with Riley, the Company leases its principal executive offices, consisting of approximately 15,384 square feet located at 29 E. Reno Avenue, Suite 500, Oklahoma City, Oklahoma 73104 at current rental of approximately $32,000 per month, expiring in April 2022.  The Company also lease an office located at 8000 E. Maplewood Ave., Suite 130, Greenwood Village, Colorado at a current rental of approximately $4,600 per month, expiring in August 2021, an office in Hays, Kansas at a rental of $750 per month that is currently a month-to-month lease and a storage yard in Hays, Kansas at a rental of $350 per month that is also a month-to month-lease.

The Company carries commercial insurance as well as property insurance on its offices, vehicles, and office contents.  As of December 31, 2020, the Company did not have an interest in producing or non-producing oil and gas properties in any state other than Kansas.  In connection with the Merger Transaction, the Company acquired the assets of REP, LLC. REP, LLC is an oil and gas exploration and production company with acreage is primarily located on large contiguous blocks in Yoakum County, Texas and Lea, Roosevelt and Chaves Counties in New Mexico; and the offset legacy assets are located in the Permian Basin San Andres fields, which include the Wasson and Brahaney Fields.

Kansas Properties

The Kansas Properties as of December 31, 2020 contained 15,265 gross acres (11,273 net acres) in central Kansas.  Of these acres, 13,440 gross acres (10,893 net acres) were held by production.

The Kansas leases typically provide for a landowner royalty of 12.5%.  Some wells are subject to an overriding royalty interest from 0.5% to 15%.  The Company maintains a 100% working interest in most of its wells and undrilled acreage in Kansas.  The primary terms for most of the Company’s newer leases in Kansas are from three to five years.

During 2020, the Company did not participate in drilling any wells.  All of the Company’s current reserve value, production, oil and gas revenue, and future development objectives result from the Company’s ongoing interest in Kansas.

Reserve and Production Summary

The following tables indicate the county breakdown of 2020 production and reserve values as of December 31, 2020.

20

Production by County

Area	Gross Production MBOE		Average Net Revenue Interest		Percentage of Total Oil Production
Rooks County, KS		70.1		0.829552		71.0	%
Trego County, KS		11.0		0.805752		11.2	%
Ellis County, KS		5.2		0.798147		5.3	%
Barton County, KS		4.3		0.811295		4.3	%
Graham County, KS		2.8		0.872264		2.8	%
Rush County, KS		2.2		0.872468		2.2	%
Russell County, KS		2.0		0.827019		2.1	%
Pawnee County, KS		1.1		0.834952		1.1	%
Total		98.7				100.0	%

Reserve Value by County Discounted at 10% (in thousands)

Area	Proved Developed		Proved Undeveloped		Proved Reserves		% of Total
Rooks County, KS	$	2,162	$	—	$	2,162		74.6	%
Trego County, KS		245		—		245		8.5	%
Rush County, KS		197		—		197		6.8
Barton County, KS		177		—		177		6.1	%
Graham County, KS		98		—		98		3.4
Pawnee County, KS		18		—		18		0.6
Ellis County, KS		—		—		—		—	%
Russell County, KS		—		—		—		—	%
Total	$	2,897	$	—	$	2,897		100.0	%

Reserve Analyses

The Company’s estimated total net proved reserves of oil and natural gas as of December 31, 2020 and 2019, and the present values of estimated future net revenues attributable to those reserves as of those dates, are presented in the following tables. All of the Company’s reserves were located in the United States. These estimates were prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”) of Dallas, Texas, and are part of their reserve reports on the Company’s oil and gas properties.  LaRoche and its employees and its registered petroleum engineers have no interest in the Company and performed those services at their standard rates.  LaRoche’s estimates were based on a review of geologic, economic, ownership, and engineering data provided to them by the Company.  In accordance with SEC regulations, no price or cost escalation or reduction was considered. The technical persons at LaRoche responsible for preparing the Company’s reserve estimates meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the standards pertaining to the estimating and auditing of oil and gas reserves information promulgated by the Society of Petroleum Engineers.  Our independent third-party engineers do not own an interest in any of our properties and are not employed by the Company on a contingent basis.

In substance, the LaRoche Report used estimates of oil and gas reserves based upon standard petroleum engineering methods which include production data, decline curve analysis, volumetric calculations, pressure history, analogy, various correlations and technical factors.  Information for this purpose was obtained from owners of interests in the areas involved, state regulatory agencies, commercial services, outside operators and files of LaRoche.

Management has established, and is responsible for, internal controls designed to provide reasonable assurance that the estimates of Proved Reserves are computed and reported in accordance with SEC rules and regulations as well as with established industry practices.  The Company’s Geologist has experience evaluating reserves on a well by well basis and on a company wide basis.   Prior to generation of the annual reserves, management and staff meet with LaRoche to review properties and discuss assumptions to be used in the calculation of reserves. Management reviews all information submitted to LaRoche to ensure the accuracy of the data.  Management also reviews the final report from LaRoche and discusses any differences from Management expectations with LaRoche.

21

Total Proved Reserves as of December 31, 2020

	Producing		Non-Producing		Undeveloped		Total
Oil (MBbl)		489		28		—		517
Future net cash flows before income taxes discounted at 10% (in thousands)	$	2,598	$	299	$	—	$	2,897

Total Proved Reserves as of December 31, 2019

	Producing		Non-producing		Undeveloped		Total
Oil (MBbl)		766		37		—		803
Future net cash flows before income taxes discounted at 10% (in thousands)	$	7,592	$	773	$	—	$	8,365

Historically, all drilling has primarily been funded by cash flows from operations, cash balances, with supplemental funding provided by the Company’s credit facility.

The oil price after basis adjustments used in our December 31, 2020 reserve valuation was $34.87 per Bbl compared to $50.65 per Bbl used in our December 31, 2019 reserve valuation.  The primary factor causing the decrease in proved developed reserve volumes and values from December 31, 2019 levels was decreased oil prices.

The assumed prices used in calculating the estimated future net revenue attributable to proved reserves do not necessarily reflect actual market prices for oil production sold after December 31, 2020.  There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices.  Accordingly, the foregoing prices should not be interpreted as a prediction of future prices.

Production

The following tables summarize for the past two fiscal years the volumes of oil produced from operated properties, the Company’s operating costs, and the Company’s average sales prices for its oil.  The net production volumes excluded volumes produced to royalty interest or other parties’ working interest.

Kansas
	Gross Production				Net Production				Cost of Net Production		Average Sales Price
Years Ended	Oil		Gas		Oil		Gas				Oil		Gas
December 31,	(MBbl)		(MMcf)		(MBbl)		(MMcf)		(Per BOE)		(Bbl)		(Per Mcf)
2020		99		—		82		—	$	32.49	$	34.91		—
2019		111		—		91		—	$	34.55	$	52.12		—

Oil and Gas Drilling Activities

During 2019, the Company participated in drilling two operated wells, one of which was completed as a producing well, and one non-operated well, which was completed as a producing well.  All of the Company’s current reserve value, production, oil and gas revenue, and future development objectives result from the Company’s ongoing interest in Kansas.

22

Gross and Net Wells

The following tables set forth the fiscal years ending December 31, 2020 and 2019 the number of gross and net development wells drilled by the Company.  The term gross wells means the total number of wells in which the Company owns an interest, while the term net wells means the sum of the fractional working interest the Company owns in the gross wells.

	For Years Ending December 31,
	2020				2019
	Gross		Net		Gross		Net
Kansas
Productive Wells		—		—		2		1.1
Dry Holes		—		—		1		0.9

Productive Wells

As of December 31, 2019, the Company held a working interest in 175 gross wells, including interest in 3 properties operated by others, and 171 net wells in Kansas.  Productive wells are either producing wells or wells capable of commercial production although currently shut-in.  The term gross wells means the total number of wells in which the Company owns an interest, while the term net wells means the sum of the fractional working interests the Company owns in all of the gross wells.

Developed and Undeveloped Oil and Gas Acreage

As of December 31, 2020, the Company owned and operated working interests in the following developed and undeveloped oil and gas acreage.  The term gross acres means the total number of acres in which the Company owns an interest, while the term net acres means the sum of the fractional working interest the Company owns in the gross acres, less the interest of royalty owners.

Developed

Undeveloped

Total

Gross Acres

Net Acres

Gross Acres

Net Acres

Gross Acres

Net Acres

Kansas

13,600

10,926

1,168

244

14,768

11,170

The following table identifies the number of gross and net undeveloped acres as of December 31, 2020 that will expire, by year, unless production is established before lease expiration or unless the lease is renewed.

	2021		2022		2023		Total
Gross Acres		320		263		585		1,168
Net Acres		67		55		122		244

ITEM 3. LEGAL PROCEEDINGS

See Item 8. Commitments and Contingencies in Notes to Consolidated Financial Statements

ITEM 4. MINE SAFETY DISCLOSURES.

Not Applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information

As of December 31, 2020, the Company’s common stock was listed on the NYSE American exchange under the symbol TGC (effective with trading on March 1, 2021, the symbol changed to REPX).    The range of high and low sales prices for shares of common stock of the Company as reported on the NYSE American during the fiscal years ended December 31, 2020 and December 31, 2019 are set forth below.  The prices set forth in the table below have been adjusted to reflect the impact of the 1 for 12 stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.

23

For the Quarters Ending	High		Low
March 31, 2020	$	8.40	$	4.44
June 30, 2020	$	9.24	$	5.16
September 30, 2020	$	13.20	$	6.00
December 31, 2020	$	52.32	$	8.64
March 31, 2019	$	14.40	$	10.20
June 30, 2019	$	16.20	$	9.60
September 30, 2019	$	12.00	$	6.60
December 31, 2019	$	7.92	$	4.68

Holders

As of December 31, 2020, the number of shareholders of record of the Company’s common stock was 244 and management believes that there are approximately 4,500 beneficial owners of the Company’s common stock.

Dividends

Tengasco, Inc did not pay any dividends with respect to the Company’s common stock in 2020 or 2019.  However, Riley did pay dividends to their owners during this period.

Recent Sales of Unregistered Securities

During the fourth quarter of fiscal 2020, the Company did not sell or issue any unregistered securities.  Any unregistered equity securities that were sold or issued by the Company during the first three quarters of fiscal 2020 were previously reported in Reports filed by the Company with the SEC.

Purchases of Equity Securities by the Company and Affiliated Purchasers

Neither the Company nor any of its affiliates repurchased any of the Company’s equity securities during 2020.

Equity Compensation Plan Information

See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matter” for information regarding the Company’s equity compensation plans.

ITEM 6. SELECTED FINANCIAL DATA

Not Applicable.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Discussion in Item 7 relates solely to operations of Tengasco, Inc. and does not include discussion related to REP, LLC operations.

Results of Operations

The Company reported a net loss from continuing operations of $(3.6 million) or $(4.10) per share in 2020 compared to a net loss of $(436,000) or $(0.49) per share in 2019.  Loss per share in 2020 and in 2019 has been adjusted for the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.

24

On October 22, 2020, we entered into the Merger Agreement, providing for an all-stock merger of with REP, LLC which successfully closed on February 26, 2021. This strategic combination accelerates our transition to a cash-return business model, including the implementation of a dividend strategy.

The Company realized revenues of approximately $3.0 million in 2020 compared to $4.9 million in 2019.  During 2020, revenues decreased approximately $1.9 million of which $1.5 million of this decrease related to a $17.18 per barrel decrease in the average oil price received from $52.12 per barrel received in 2019 to $34.94 per barrel received in 2020.  Revenue also decreased approximately $387,000 related to a 7.4 MBbl decrease in oil sales volumes from 93.7 MBbl in 2019 to 86.3 MBbl in 2020.  The decrease in volumes was primarily related to lower sales volumes on the Veverka D lease due to declines from increased volumes associated with the polymer work performed in mid-2018, lower sales volumes on the Bellerive Stice well that was completed at the end of 2018, as well as natural declines on other properties, partially offset by sales from the Zimmerman well that was completed at the end of 2019.

The Company’s production costs and taxes were approximately $3.1 million in 2020 compared to $3.4 million in 2019.  The $294,000 decrease in 2020 was primarily due to lower well repair and utility costs, partially offset by a change in the oil inventory adjustment and an increase in Kansas payroll costs.

Depreciation, depletion, and amortization was approximately $644,000 in 2020 compared to $716,000 in 2019.  The $72,000 decrease in 2020 was due to a $50,000 decrease related to lower sales volumes, a $17,000 decrease related to a decrease in the oil and gas depletion rate, and a $5,000 decrease in depreciation on field vehicles.

The Company’s general and administrative cost was approximately $2.2 million in 2020 compared to $1.3 million in 2019.  The $885,000 increase in 2020 was primarily due to costs related to the Merger Transaction with REP, LLC.

The Company performed its assessment for impairment of oil and gas properties and other assets during 2020 and 2019.  During 2020, the Company recorded impairment of approximately $920,000 primarily as a result of lower oil prices experienced during 2020.  During 2019, no impairments of oil and gas properties or other assets resulted from the Company’s assessment.

Other income was $166,000 in 2020 compared to $6,000 in 2019.  The amount recorded in 2020 related to forgiveness of the Company’s Paycheck Protection Program (“PPP”) loan.  On November 5, 2020, the Company was notified by Prosperity Bank PPP loan had been forgiven and the loan was closed.

During 2020 and 2019, the Company did not have any open derivative positions.

Liquidity and Capital Resources

At December 31, 2020, the Company had a revolving credit facility with Prosperity Bank.  Upon closing the Merger Transaction with Riley on February 26, 2021, the credit facility with Prosperity Bank was terminated.  Other than cash flow from operations, this credit facility has historically been the Company’s primary source to fund working capital and future capital spending.  Under the credit facility, loans and letters of credit were 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 December 31, 2020, the Company’s borrowing base was $3.1 million, subject to a credit limit based on current covenants of approximately $1.442 million.  The credit facility was secured by substantially all of the Company’s producing and non-producing oil and gas properties.  The credit facility included certain covenants with which the Company was required to comply.  At December 31, 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 December 31, 2020, the interest rate on this credit facility was 3.75%.  The Company was in compliance with all covenants as of December 31, 2020 and 2019.

The Company had zero borrowings under the facility on December 31, 2020 and December 31, 2019.  As the credit facility was terminated on February 26, 2021, no further borrowing base reviews will take place.

Net cash used in operating activities was $1.5 million in 2020 compared to $226,000 provided by operating activities in 2019.  In 2020, cash flow provided by working capital was $571,000 compared to $163,000 of cash flow used in working capital during 2019.  The change in cash used in operating activities during 2020 was primarily related to decreased revenues as a result of lower oil prices, and decreased revenues as a result of lower sales volumes, and increase in general and administrative expenses primarily as a result of costs related to the Merger Transaction with Riley.

25

Net cash used in investing activities was $71,000 in 2020 compared to $233,000 in 2019.  The $162,000 decrease in cash used in investing activities during 2020 was due primarily to drilling and polymer costs incurred during 2019, and proceeds from the sale of equipment inventory in 2019.

Net cash provided by financing activities was $126,000 in 2020 compared to $106,000 used in financing activities in 2019.  The change in net cash provided by financing activities was due the Company receiving approximately $166,000 from the Paycheck Protection Program (“PPP”) loan in May 2020.  This loan was forgiven in November 2020.

On February 26, 2021, the Company completed an all-stock merger with REP, LLC. On the closing date of the Merger Transaction, each common unit of REP, LLC was automatically converted into the right to receive 97.796467 shares of Company common stock. This exchange ratio has not been adjusted for the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.  Based on the closing price of the Company’s common stock on February 26, 2021, the total value of the Company common stock issued to holders of REP, LLC common units as part of the Merger Transaction was approximately $500 million.

With this strategic merger, we are accelerating our transition to a cash-return business model, which moderates growth, emphasizes capital efficiencies and prioritizes cash returns to shareholders. These principles will position the Company to be a consistent builder of economic value through the cycle. The post-merger scalability is expected to enhance the Company’s free cash flow, credit profile and decrease the overall cost of capital.

Critical Accounting Policies

The Company prepares its Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America, which require the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year.  Actual results could differ from those estimates.  The Company considers the following policies to be the most critical in understanding the judgments that are involved in preparing the Company’s financial statements and the uncertainties that could impact the Company’s results of operations, financial condition and cash flows.

Revenue Recognition

The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Revenues are recognized when the performance obligations are satisfied and when it transfers control of goods or services 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 them to pick up the crude oil from the storage tanks.  When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized.  The sales 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.  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.

The Company operates certain salt water disposal wells, some of which accept water from third parties.  The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells.  In some cases, the contract is based on 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 in a given month, the Company has met its contractual obligations and revenues are recognized for that month.

The following table presents the disaggregated revenue by commodity for the years ended December 31, 2019, and 2018 (in thousands):

	Year Ended		Year Ended
	December 31, 2020		December 31,2019
Revenue (in thousands):
Crude oil	$	3,015	$	4,884
Salt water disposal fees		23		27
Total	$	3,038	$	4,911

26

There were no natural gas imbalances at December 31, 2020 or December 31, 2019.

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 both December 31, 2020 and 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 value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil 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 cost or estimated  fair value of unproven properties included in the cost being amortized (ceiling).  If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down cannot be reversed in a later period.

Oil and Gas Reserves/Depletion, Depreciation, and Amortization of Oil and Gas Properties

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 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’s proved oil and gas reserves as of December 31, 2020 were determined by LaRoche Petroleum Consultants, Ltd.  Projecting the effects of commodity prices on production, and timing of development expenditures includes many factors beyond the Company’s control.  The future estimates of net cash flows from the Company’s proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time.  Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates.

Asset Retirement Obligations

The Company’s asset retirement obligations relate to the plugging, dismantling, and removal of wells drilled to date. The Company follows the requirements of FASB ASC 410, “Asset Retirement Obligations and Environmental Obligations”. Among other things, FASB ASC 410 requires entities to record a liability and corresponding increase in long-lived assets for the present value of material obligations associated with the retirement of tangible long-lived assets. Over the passage of time, accretion of the liability is recognized as an operating expense and the capitalized cost is depleted over the estimated useful life of the related asset.  If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates and changes in the estimated timing of abandonment.  The Company currently uses an estimated useful life of wells typically ranging from 20-40 years.  Management continues to periodically evaluate the appropriateness of these assumptions.

27

Income Taxes

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

Realization of deferred 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 a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency.  A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated.

The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position.  The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized.

Recent Accounting Pronouncements

See Item 2. Recent Accounting Pronouncements in Notes to Consolidated Financial Statements

Contractual Obligations

The following table summarizes the Company’s contractual obligations due by period as of December 31, 2020 (in thousands):

Contractual Obligations	Total		2021		2022		2023
Long-Term Debt Obligations1	$	—	$	—	$	—	$	—
Operating Lease Obligations		42		42		—		—
Finance Lease Obligations		77		61		16		—
Estimated Interest on Obligations		2		2		—		—
Total	$	121	$	105	$	16	$	—

(1) The credit facility with Prosperity Bank had a zero balance at December 31, 2020.  Upon closing the Merger Transaction with Riley on February 26, 2021, the credit facility with Prosperity Bank was terminated.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS

Discussion in Item 7A relates solely to operations of Tengasco, Inc. and does not include discussion related to Riley operations.

Commodity Risk

The Company’s major market risk exposure is in the pricing applicable to its oil and gas production.  Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production.  Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue.  Monthly oil price realizations during 2020 ranged from a low of $15.26 per barrel to a high of $53.04 per barrel.  During 2020, the industry has seen a severe decline in oil commodity pricing from year-end 2019 pricing due to economic conditions worldwide caused by the novel virus outbreak which resulted in a significant decline in demand for oil, combined with an oil price war between Saudi Arabia and Russia which further depressed crude oil pricing.  The Company can operate in the short-term at these depressed levels, but would need to access additional capital should prices continue at these depressed level for an extended period of time.

In addition, during 2010, 2011, and 2012 the Company participated in derivative agreements on a specified number of barrels of oil of its production.  The Company did not participate in any derivative agreements during 2020 or 2019 but may participate in derivative activities in the future.

28

Interest Rate Risk

At December 31, 2020, the Company had finance leases outstanding of approximately $77,000,  and no amounts owed on its credit facility with Prosperity Bank.  As of December 31, 2020, the interest rate on the credit facility was variable at a rate equal to prime plus 0.50% per annum.  The Company’s credit facility interest rate at December 31, 2020 was 3.75%.  The Company’s finance leases of $77,000 has fixed interest rates ranging from approximately 5.0% to 6.5%.

The annual impact on interest expense 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 December 31.  The Company did not have any open derivative contracts relating to interest rates at December 31, 2020 or 2019.

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 would 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, 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 and gas prices or prolonged periods of low prices may substantially adversely affect the Company’s financial position, results of operations, and cash flows.

See CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS on page 3.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

The financial statements and supplementary data commence on page F-1.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A. CONTROLS AND PROCEDURES

Discussion in Item 9A relates solely to operations of Tengasco, Inc. and does not include discussion related to Riley operations.

The Company’s Chief Executive Officer and Chief Financial Officer, and other members of management have evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based on such evaluation, the Company’s Chief Executive Officer and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures, as of the end of the period covered by this Report, were adequate and effective to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

The effectiveness of a system of disclosure controls and procedures is subject to various inherent limitations, including cost limitations, judgments used in decision making, assumptions about the likelihood of future events, the soundness of internal controls, and fraud.  Due to such inherent limitations, there can be no assurance that any system of disclosure controls and procedures will be successful in preventing all errors or fraud, or in making all material information known in a timely manner to the appropriate levels of management.

29

Management’s Annual Report on Internal Control Over Financial Reporting

Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Securities Exchange Act of 1934.  Internal control over financial reporting refers to the process designed by, or under the supervision of the Company’s Chief Executive Officer and Chief Financial Officer, and effected by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:

• Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company’s assets;

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of the Company’s management and directors; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.  Also, projections of any evaluation of effectiveness into future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company internal control over financial reporting as of December 31, 2020.  In making this assessment, the Company’s management used the criteria set forth in the framework in “Internal Control-Integrated-Framework” issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). This framework was updated in 2013.  Based on the evaluation conducted under the framework in “Internal Control- Integrated Framework,” issued by COSO the Company’s management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2020.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting.  Management’s report was not subject to attestation by our registered public accounting firm pursuant to rules of the Securities and Exchange Commission that permit the Company to provide only management’s report in this Annual Report on Form 10-K.

Changes in Internal Control Over Financial Reporting

During the year ended December 31, 2020, there have been no changes to the Company’s system of internal controls over financial reporting that have materially affected, or are reasonably likely to materially affect, the Company’s system of controls over financial reporting.  As part of a continuing effort to improve the Company’s business processes, management is evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes or accounting procedures.

ITEM 9B. OTHER INFORMATION

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 Riley. Pursuant to the terms of the Merger Agreement, a business combination between the Registrant and Riley was effected through the merger of Merger Sub with and into Riley, with Riley surviving as the surviving company and as a wholly owned subsidiary of the Registrant (the “Merger” and, collectively with the other transactions described in the Merger Agreement, the “Merger Transaction”). 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, Riley Exploration – Permian, LLC and Riley Permian Operating Company, LLC.  The shares of the Company began trading under the ticker symbol REPX on the NYSE American on March 1, 2021.

30

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE

Identification of Directors and Executive Officers – The table below relates to Company directors as of December 31, 2020.

NAME	POSITIONS HELD	DATE OF INITIAL ELECTION OR DESIGNATION	AGE
Matthew K. Behrent	Director	3/27/2007	50
Peter E. Salas	Director;	10/8/2002	66
	Chairman of the Board	10/21/2004
Richard M. Thon	Director	11/22/2013	66
Michael J. Rugen	Chief Financial Officer;	9/28/2009	60
	Chief Executive Officer (interim)	6/24/2013
Cary V. Sorensen	Vice-President; General Counsel; Secretary	7/9/1999	72

Business Experience

Directors

In accordance with the Merger Agreement, on February 26, 2021, immediately prior to and effective upon the closing of the Merger, Peter Salas, Richard M. Thon and Matthew K. Behrent resigned from the Company’s board of directors and committees of the board of directors on which they respectively served, which resignations were not the result of any disagreements with the Company relating to the Company’s operations, policies or practices.

The Merger Agreement provides that at or immediately after the closing of the Merger, the size of the Company’s board of directors will be increased to five members, consisting of one director designated by the Company, who is Michael J. Rugen, two directors designated by REP LLC, who are Bobby D. Riley and Bryan H. Lawrence, and two independent director nominees, Brent Arriaga and E. Wayne Nordberg.

The information below represents information on the Tengasco directors as of December 31, 2020.

Matthew K. Behrent is the Executive Vice President, Corporate Development of EDCI Holdings, Inc., a company that is currently engaged in carrying out a plan of dissolution. Before joining EDCI in June, 2005, Mr. Behrent was an investment banker, working as a Vice-President at Revolution Partners, a technology focused investment bank in Boston, from March 2004 until June 2005 and as an associate in Credit Suisse First Boston Corporation's technology mergers and acquisitions group from June 2000 until January 2003. From June 1997 to May 2000, Mr. Behrent practiced law, most recently with Cleary, Gottlieb, Steen & Hamilton in New York, advising financial sponsors and corporate clients in connection with financings and mergers and acquisitions transactions. Mr. Behrent received his J.D. from Stanford Law School in 1997, and his B.A. in Political Science and Political Theory from Hampshire College in 1992. He became a Director of the Company on March 27, 2007.   The experience, qualifications, attributes, and skills gained by Mr. Behrent in these sophisticated legal and financial positions directly apply to and support the financial oversight of the Company’s operations and lead to the conclusion that Mr. Behrent should serve as a Director of the Company.

Peter E. Salas has been President of Dolphin Asset Management Corp. and its related companies since he founded it in 1988.  Prior to establishing Dolphin, he was with J.P. Morgan Investment Management, Inc. for ten years, becoming Co-manager, Small Company Fund and Director-Small Cap Research.  He received an A.B. degree in Economics from Harvard in 1978.  Mr. Salas was elected to the Board of Directors on October 8, 2002.  The business experience, attributes, and skills gained by Mr. Salas in these sophisticated financial positions, together with his service as director of other public companies and his capacity as controlling person of the Company’s largest shareholder directly apply to and support his qualification as a director, and lead to the conclusion that Mr. Salas should serve as a Director of the Company.

31

Richard M. Thon began a career with ARAMARK Corporation in 1987.  ARAMARK is based in Philadelphia, has 280,000 employees worldwide, and provides food services, facilities management, and uniform and career apparel to health care institutions, universities, and businesses in 21 countries.  Mr. Thon served in various capacities in the Corporate Finance Department of ARAMARK culminating with the position of Assistant Treasurer when he retired in June 2002.  His responsibilities included bank credit agreements, public debt issuance, interest rate risk management, foreign subsidiary credit agreements, foreign exchange, letters of credit, insurance finance, off-balance-sheet finance, and real estate and equipment leasing. Prior to joining ARAMARK, Mr. Thon was a Vice President in the International Department of Mellon Bank.  Since his retirement in 2002, Mr. Thon has served in a variety of volunteer charitable and civic activities. Mr. Thon received a B.A. in Economics degree from Yale College in 1977 and a Masters of Business Administration degree in Finance from The Wharton School, University of Pennsylvania in 1979.  Mr. Thon’s experience in the fields of banking and finance directly apply to the business needs of the Company and lead to the conclusion that he will provide significant benefit to the Board and that he is qualified to serve as a Director of the Company.

Officers

On February 26, 2021, effective immediately after the closing of the Merger, the Company’s board of directors appointed Bobby D. Riley as the Company’s Chairman of the Board and Chief Executive Officer, Kevin Riley as the Company’s President, Michael J. Rugen as the Company’s Chief Financial Officer and Director, Corey Riley as the Company’s Executive Vice President Business Intelligence and Michael Palmer as the Company’s Executive Vice President Corporate Land. On March 15, 2021, Philip Riley joined the Company as Executive Vice President of Strategy.  The information below represents information on the Tengasco officers as of December 31, 2020.

As a result of the Merger Transaction with Riley which closed on February 26, 2021, Cary V. Sorensen was removed as an officer of the Company and its subsidiaries at closing of the merger.  Michael Rugen will continue as Chief Financial Officer of Riley Exploration Permian, Inc., following the closing of the Merger Transaction with Riley.  The information below represents information on the Tengasco officers as of December 31, 2020.

Michael J. Rugen was named Chief Financial Officer of the Company in September 2009 and as interim Chief Executive Officer in June 2013.  He is a certified public accountant (Texas) with over 35 years of experience in exploration, production and oilfield service.  Prior to joining the Company, Mr. Rugen spent 2 years as Vice President of Accounting and Finance for Nighthawk Oilfield Services.  From 2001 to June 2007, he was a Manager/Sr. Manager with UHY Advisors, primarily responsible for managing internal audit and Sarbanes-Oxley 404 engagements for various oil and gas clients. In 1999 and 2000, Mr. Rugen provided finance and accounting consulting services with Jefferson Wells International.  From 1982 to 1998, Mr. Rugen held various accounting and management positions at BHP Petroleum, with accounting responsibilities for onshore and offshore US operations as well as operations in Trinidad and Bolivia.  Mr. Rugen earned a Bachelor of Science in Business with a Major in Accounting in 1982 from Indiana University.

Cary V. Sorensen is a 1976 graduate of the University of Texas School of Law and has undergraduate and graduate degrees from North Texas State University and Catholic University in Washington, D.C. Prior to joining the Company in July 1999, he had been continuously engaged in the practice of law in Houston, Texas relating to the energy industry since 1977, both in private law firms and a corporate law department, serving for seven years as senior counsel with the oil and gas litigation department of a Fortune 100 energy corporation in Houston before entering private practice in June, 1996.  He has represented virtually all of the major oil companies headquartered in Houston as well as local distribution companies and electric utilities in a variety of litigated and administrative cases before state and federal courts and agencies in nine states.  These matters involved gas contracts, gas marketing, exploration and production disputes involving royalties or operating interests, land titles, oil pipelines and gas pipeline tariff matters at the state and federal levels, and general operation and regulation of interstate and intrastate gas pipelines.  He has served as General Counsel of the Company since July 9, 1999.

Family and Other Relationships

As of December 31, 2020 there were no family relationships between any of the directors or executive officers of the Company. Following the Closing Date, there is a family relationship between Mr. Bobby D. Riley and the Company’s President, Mr. Kevin Riley, and the Company’s Executive Vice President Business Intelligence, Mr. Corey Riley, as father and sons. Mr. Kevin Riley and Mr. Corey Riley are brothers. There is no family relationship between Mr. Philip Riley and Messrs. Bobby Riley, Kevin Riley, or Corey Riley.

Involvement in Certain Legal Proceedings

To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficially 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.

32

To the knowledge of management, during the past ten years, unless specifically indicated below with respect to any numbered item, no present director, executive officer or person nominated to become a director or an executive officer of the Company:

(1) Filed a petition under the federal bankruptcy laws or any state insolvency law, nor had a receiver, fiscal agent or similar officer appointed by a court for the business or property of such person, or any partnership in which he or she was a general partner at or within two years before the time of such filing, or any corporation or business association of which he or she was an executive officer at or within two years before the time of such filing; provided however that:

Peter E. Salas, a director of the Company and Chairman of the Board of the Company was the chief executive officer of Boston Restaurant Associates, Inc. when that company filed a Chapter 11 reorganization plan under federal bankruptcy laws on May 20, 2015. The plan of reorganization became effective on August 31, 2015 and Mr. Salas has remained the chief executive officer and sole director of that company since the reorganization.  In addition, Mr. Salas was controlling person of the general partner of Hoactzin Partners, L.P. (“Hoactzin”) when on October 26, 2019 Hoactzin filed a petition under Chapter 11 of the Bankruptcy Code in the Northern District of Texas in Dallas.  On February 12, 2020 the proceeding was converted to a Chapter 7 liquidation proceeding.  At the time of this Report, the case was proceeding in due course.

(2) Was convicted in a criminal proceeding or named the subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);

(3) Was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily enjoining him or her from or otherwise limiting the following activities: (a) acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant, any other person regulated by the Commodity Futures Trading Commission (“CFTC”), or an associated person of any of the foregoing, or as an investment adviser, underwriter, broker or dealer in securities, or as an affiliated person, director or employee of any investment company, bank, savings and loan association or insurance company, or engaging in or continuing any conduct or practice in connection with such activity; (b) engaging in any type of business practice; or (c) engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of federal or state securities laws or federal commodities laws;

(4) Was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting him or her for more than 60 days from engaging in any activity described in paragraph 3(a) above, or being associated with any persons engaging in any such activity;

(5) Was found by a court of competent jurisdiction in a civil action or by the SEC to have violated any federal or state securities law, and the judgment in such civil action or finding by the SEC has not been subsequently reversed, suspended, or vacated;

(6) Was found by a court of competent jurisdiction in a civil action or by  the CFTC to have violated any federal  commodities law, and the judgment in such civil action or finding by the  CFTC has not been subsequently reversed, suspended, or vacated;

(7) Was the subject of, or a party to, any federal or state judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated, relating to an alleged violation of: (i) any federal or state securities or commodities law or regulation; (ii) any law or regulation respecting financial institutions or insurance companies including but not limited to a temporary or permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease and desist order, or removal or prohibition order; or (iii) any law or regulation prohibiting mail or wire fraud or fraud in connection with any business entity; or

(8) Was the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26) of the Exchange Act [15 U.S.C. 78c(a)(26)], any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act [7 U.S.C. 1(a)(29)], or any equivalent exchange, association, entity or organization that has disciplinary authority over its members or persons associated with a member.

33

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers, directors and persons who beneficially own more than 10% of the Company’s common stock to file initial reports of ownership and reports of changes in ownership with the SEC no later than the second business day after the date on which the transaction occurred unless certain exceptions apply. In fiscal 2020, the Company, its officers, directors, and shareholders owning more than 10% of its common stock were not delinquent in filing of any of their Form 3, 4, and 5 reports.

Code of Ethics

The Company’s Board of Directors has adopted a Code of Ethics that applies to the Company’s financial officers and executive officers, including its Chief Executive Officer and Chief Financial Officer.  The Company’s Board of Directors has also adopted a Code of Conduct and Ethics for Directors, Officers and Employees.  A copy of these codes can be found at the Company’s internet website at www.rileypermian.com.  The Company intends to disclose any amendments to its Codes of Ethics, and any waiver from a provision of the Code of Ethics granted to the Company’s President, Chief Financial Officer or persons performing similar functions, on the Company’s internet website within five business days following such amendment or waiver.  A copy of the Code of Ethics can be obtained free of charge by writing to Beth di Santo, Corporate Secretary, Riley Exploration Permian, Inc., 29 East Reno Avenue, Suite 500, Oklahoma City, OK 73104.

Audit Committee

As a result of the Merger Transaction with Riley which closed on February 26, 2021, all Tengasco Audit Committee members resigned at closing.  The information below represents information on the Tengasco Audit Committee members as of December 31, 2020.

During 2020, directors Matthew K. Behrent and Richard M. Thon were the members of the Board’s Audit Committee. Mr. Behrent was the Chairman of the Committee and the Board of Directors determined that both Mr. Behrent and Mr. Thon were each an “audit committee financial expert” as defined by applicable Securities and Exchange Commission (“SEC”) regulations and the NYSE American Rules.  Each of the members of the Audit Committee met the independence and experience requirements of the NYSE American Rules, the applicable Securities Laws, and the regulations and rules promulgated by the SEC. The Audit Committee met each quarter and a total of four (4) times in Fiscal 2019 with the Company’s auditors, including discussing the audit of the Company’s year-end financial statements.

The Audit Committee adopted an Audit Committee Charter during fiscal 2001.  In 2004, the Board adopted an amended Audit Committee Charter.  The Audit Committee Charter fully complies with the requirements of the NYSE American Rules. The Audit Committee reviews and reassesses the Audit Committee Charter annually.

The Audit Committee's functions are:

• To review with management and the Company’s independent auditors the scope of the annual audit and quarterly statements, significant financial reporting issues and judgments made in connection with the preparation of the Company’s financial statements;

• To review major changes to the Company’s auditing and accounting principles and practices suggested by the independent auditors;

• To monitor the independent auditor's relationship with the Company;

• To advise and assist the Board of Directors in evaluating the independent auditor's examination;

• To supervise the Company's financial and accounting organization and financial reporting;

• To nominate, for approval of the Board of Directors, a firm of certified public accountants whose duty it is to audit the financial records of the Company for the fiscal year for which it is appointed; and

• To review and consider fee arrangements with, and fees charged by, the Company’s independent auditors.

Changes in Board Nomination Procedures

In 2020, there were no changes to the procedures adopted by the Board for nominations for the Board of Directors. Those procedures were last set forth in the Company’s Proxy Statement filed on October 3, 2014 for the Company’s Annual Meeting held on November 14, 2014 and were posted on the Company’s internet website.  In the event of any such amendment to the procedures, the Company intends to disclose the amendments on the Company's internet website within five business days following such amendment.

34

ITEM 11. EXECUTIVE COMPENSATION

Executive Officer Compensation

The following table sets forth a summary of all compensation awarded to, earned or paid to, the Company's Chief Executive Officer, Chief Financial Officer, other executive officers, and employees whose compensation exceeded $100,000 during fiscal years ended December 31, 2020 and December 31, 2019.

SUMMARY COMPENSATION TABLE

Name and Principal Position	Year	Salary ($)		Bonus ($)		Stock Awards ($)		All Other Compensation2 ($)		Total ($)
Michael J. Rugen,	2020		199,826		23,944		10,633		8,132		242,535
Chief Financial Officer	2019		199,826		23,507		12,147		8,128		243,608
Chief Executive Officer (interim)3
Cary V. Sorensen,	2020		91,000		—		—		3,720		94,720
General Counsel	2019		91,000		—		—		3,707		94,707

(2) The amounts in this column consist of the Company’s matching contributions to its 401 (k) plan and the portion of company-wide group term life insurance premiums allocable to these named executive officers.

(3) Mr. Rugen was appointed interim Chief Executive Officer on June 28, 2013.  The bonus and stock award information for Mr. Rugen for 2020 and 2019 represents his compensation for his services as CEO.

Outstanding Equity Awards at Fiscal Year-End

	OPTION AWARDS
Name	Number of securities underlying unexercised options exercisable		Number of securities underlying unexercised options unexercisable		Option exercise price		Option expiration date
Michael J. Rugen		—		—	$	—
Cary V. Sorensen		—		—	$	—

Option and Award Exercises

On December 31, 2020, Peter Salas exercised approximately 52 options (this share count has been adjusted for the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021) which represented all of his options then outstanding.  No other options were exercised during 2020 or 2019.

Employment Contracts and Compensation Agreements

On September 18, 2013, the Company and its Chief Financial Officer and interim Chief Executive Officer Michael J. Rugen entered into a written Compensation Agreement as reported on Form 8-K filed on September 24, 2013.  Under the terms of the Compensation Agreement, Mr. Rugen’s annual salary will increase from $150,000 to $170,000 per year in his capacity as Chief Financial Officer, and he will receive a bonus of $7,500 per quarter for each quarter during which he also serves as interim Chief Executive Officer.  At June 1, 2014, Mr. Rugen’s salary was increased to $199,826 per year in his capacity as Chief Financial Officer, the quarterly bonus received while in the capacity as interim Chief Financial Officer was increased to $8,815 per quarter.  The increases at June 1, 2014 were for cost of living adjustments related to the relocation of the corporate office from Knoxville to Greenwood Village.  The Compensation agreement is not an employment contract, but does provide that in the event Mr. Rugen were terminated without cause, he would receive a severance payment in the amount of six month’s salary in effect at the time of any such termination.

35

On February 25, 2015, the Company and its Vice President, General Counsel, and Corporate Secretary Cary V. Sorensen entered into a written Compensation Agreement as reported on Form 8-K filed on February 19, 2015.  Under the terms of the Compensation Agreement, effective March 2, 2015, Mr. Sorensen’s annual salary will be reduced from $137,500 to $91,000 in consideration of the Company's agreement to permit Mr. Sorensen to serve as a full time employee from a virtual office in Galveston, Texas with presence in the Denver area headquarters as required. He will remain eligible for certain existing benefits: 401-K plan, bonus potential; Company-paid state bar membership dues and charges, and mobile phone charges. The Company also pays reasonable and customary office operating expenses. The Company would pay for business travel on a mileage basis and out of pocket travel costs. However, as to health insurance, Mr. Sorensen will obtain a combination of private/governmental health and disability insurance in lieu of the Company plans, with the Company reimbursing up to $13,000 per year in premiums incurred by him.

On February 19, 2015, in response to the global market factors affecting revenues from sales of the Company’s production of crude oil, the Board of Directors of the Company implemented reductions in the compensation of the Company’s officers.

As to the Company’s Chief Financial Officer and interim Chief Executive Officer Michael J. Rugen, Mr. Rugen’s salary as CFO and bonus as CEO was reduced effective February 2, 2015 by 18% from current levels, or about $42,000 per year. The 18% reduction will remain in place until 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 when his compensation shall revert to the levels in place before the reductions became effective. 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 to Mr. Rugen if he was still employed by the Company. Mr. Rugen expressly consented to this reduction as not constituting a “termination without Cause” under the terms of his Compensation Agreement dated September 18, 2013 but permitting him to invoke that provision in the event prices do recover as set out above but the compensation reduction is not rescinded or the reductions are not repaid.  As of the closing of the Merger Transaction with Riley, the potential reimbursement of this amount and shares were no longer due to Mr. Rugen.

As to the Company’s Vice President, General Counsel, and Corporate Secretary Cary V. Sorensen, the Company and Mr. Sorensen reached agreement on February 25, 2015 that as of March 2, 2015 his annual salary would be set at $91,000 per annum, a reduction from his current salary of $137,500 per annum as described above. In addition, Mr. Sorensen’s $91,000 salary will be reduced effective March 2, 2015 by 10%. In like manner as set out above for Mr. Rugen, the 10% reduction on Mr. Sorensen’s salary will remain in place until 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 when his salary shall revert to $91,000 per annum.  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 from the $91,000 salary level will be reimbursed to Mr. Sorensen if he were still employed by the Company.  As of the closing of the Merger Transaction with Riley, the potential reimbursement of this amount and shares are no longer due to Mr. Sorensen.

There are presently no other employment contracts relating to any member of management. However, depending upon the Company's operations and requirements, the Company may offer long-term contracts to executive officers or key employees in the future.

On February 25, 2021, the Company entered into a Change of Control Agreement with Michael J. Rugen and Cary V. Sorensen.  These agreements called for a severance payment in contemplation of termination of employment in the amount of six month’s salary in effect at the time of any such termination.  On March 4, 2021, Michael J. Rugen entered into an employment agreement with Riley Exploration Permian, Inc.  This employment agreement had an effective date of February 26, 2021 and supersedes the Change of Control Agreement dated February 25, 2021.

Compensation and Stock Option Committee

As a result of the Merger Transaction with Riley which closed on February 26, 2021, all Tengasco Compensation and Stock Option Committee members resigned at closing.  The information below represents information on the Tengasco Compensation and Stock Option Committee members as of December 31, 2020.

The members of the Compensation Committee during 2020 were Matthew K. Behrent and Richard M. Thon, with Mr. Thon acting as Chairman.  Messrs. Behrent and Thon meet the current independence standards established by the NYSE American Rules to serve on this Committee.

36

The Board of Directors has adopted a charter for the Compensation Committee which is available at the Company’s internet website, www.rileypermian.com.

The Compensation Committee’s functions, in conjunction with the Board of Directors, are to provide recommendations with respect to general and specific compensation policies and practices of the Company for directors, officers and other employees of the Company.  The Compensation Committee expects to periodically review the approach to executive compensation and to make changes as competitive conditions and other circumstances warrant and will seek to ensure the Company's compensation philosophy is consistent with the Company's best interests and is properly implemented. The Committee determines or recommends to the Board of Directors for determination the specific compensation of the Company’s Chief Executive Officer and all of the Company’s other officers. Although the Committee may seek the input of the Company’s Chief Executive Officer in determining the compensation of the Company’s other executive officers, the Chief Executive Officer may not be present during the voting or deliberations with respect to his compensation. The Committee may not delegate any of its responsibilities unless it is to a subcommittee formed by the Committee, but only if such subcommittee consists entirely of directors who meet the independence requirements of the NYSE American Rules.

The Compensation Committee is also charged with administering the Tengasco, Inc. Stock Incentive Plan (the “Stock Incentive Plan”).  The Compensation Committee has complete discretionary authority with respect to the awarding of options, stock, and Stock Appreciation Rights (“SARs”), under the Stock Incentive Plan, including, but not limited to, determining the individuals who shall receive options and SARs; the times when they shall receive them; whether an option shall be an incentive or a non-qualified stock option; whether an SAR shall be granted separately, in tandem with or in addition to an option; the number of shares to be subject to each option and SAR; the term of each option and SAR; the date each option and SAR shall become exercisable; whether an option or SAR shall be exercisable in whole, in part or in installments and the terms relating to such installments; the exercise price of each option and the base price of each SAR; the form of payment of the exercise price; the form of payment by the Company upon the exercise of an SAR; whether to restrict the sale or other disposition of the shares of common stock acquired upon the exercise of an option or SAR; to subject the exercise of all or any portion of an option or SAR to the fulfillment of a contingency, and to determine whether such contingencies have been met; with the consent of the person receiving such option or SAR, to cancel or modify an option or SAR, provided such option or SAR as modified would be permitted to be granted on such date under the terms of the Stock Incentive Plan; and to make all other determinations necessary or advisable for administering the Plan.

The Committee has the authority to retain a compensation consultant or other advisors to assist it in the evaluation of compensation and has the sole authority to approve the fees and other terms of retention of such consultants and advisors and to terminate their services. The Committee did not retain any such consultants or advisors in 2019 or 2018.

Compensation of Directors

The Board of Directors has resolved to compensate members of the Board of Directors for attendance at meetings at the rate of $250 per day, together with direct out-of-pocket expenses incurred in attendance at the meetings, including travel. The Directors, as of the date of this Report, have waived all such fees due to them for prior meetings.

Members of the Board of Directors may also be requested to perform consulting or other professional services for the Company from time to time, although at this time no such arrangements are in place.  The Board of Directors has reserved to itself the right to review all directors' claims for compensation on an ad hoc basis.

Board members currently receive fees from the Company for their services as director.   They may also from time to time be granted stock options or common stock under the Tengasco, Inc. Stock Incentive Plan. A separate plan to issue cash and/or shares of stock to independent directors for service on the Board and various committees was authorized by the Board of Directors and approved by the Company’s shareholders.  However, no award was made to any independent director under that separate plan in Fiscal 2019.

On February 19, 2015, in response to the global market factors affecting revenues from sales of the Company’s production of crude oil, the Board of Directors of the Company implemented reductions in the compensation of the Company’s directors.  The reductions on the directors’ compensation will remain in place until 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 when then their compensation will revert to pre-reduction levels.  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 from pre-reduction compensation levels would be reimbursed to the directors if they were still directors of the Company.  As of the closing of the Merger Transaction with Riley, the potential reimbursement of this amount and shares are no longer due to the directors.

37

DIRECTOR COMPENSATION FOR FISCAL 2020

	Fees earned or paid in cash		Stock awards compensation4		Total
Name	($)		($)		($)
Matthew K. Behrent	$	15,000	$	1,145	$	16,145
Richard M. Thon	$	15,000	$	1,145	$	16,145
Peter E. Salas	$	15,000	$	1,145	$	16,145

(4) The amounts represented in this column are equal to the aggregate grant date fair value of the award computed in accordance with FASB ASC Topic 718, Compensation-Stock Compensation, in connection with options granted under the Tengasco, Inc. Stock Incentive Plan.  See Note 11 Stock and Stock Options in the Notes to Consolidated Financial Statements included in the Company's Annual Report on Form 10-K for the year ended December 31, 2020 for information on the relevant valuation assumptions.

As of December 31, 2020, Mr. Behrent held 52 unexercised options; and Mr. Thon held 52 unexercised options.  The number of unexercised options have been adjusted to reflect the impact of the 1 for 10 reverse stock split approved at the shareholder meeting dated March 21, 2016, effective with trading on March 24, 2016 and adjusted to reflect the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.  The unexercised options held by Messrs. Behrent and Thon expired by their own terms on January 3, 2021.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDERS MATTERS

The following table sets forth the shareholdings of those persons who owned more than 5% of the Company's common stock as of December 31, 2020 with these computations being based upon 890,420 shares of common stock being outstanding as of that date and as to each shareholder, as it may pertain, assumes the exercise of options or warrants granted or held by such shareholder that are exercisable as of December 31, 2020. The number of shares have been adjusted to reflect the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.

FIVE PERCENT STOCKHOLDERS ⁵

Name and Address	Title	Number of Shares Beneficially Owned	Percent of Class
Dolphin Offshore Partners, L.P. c/o Dolphin Mgmt. Services, Inc. P.O. Box 16867 Fernandina Beach, FL 32035	Stockholder	440,687	49.5%

(5) Unless otherwise stated, all shares of Common Stock are directly held with sole voting and dispositive power.  The shares set forth in the table are as of December 31, 2020.

38

SECURITY OWNERSHIP OF DIRECTORS AND OFFICERS - The table below relates to Company directors and officers as of December 31, 2020.

Name and Address	Title	Number of Shares Beneficially Owned 6	Percent of Class 7
Matthew K. Behrent (8)	Director	5,367	Less than 1%
Michael J. Rugen (9)	Chief Executive Officer (interim); Chief Financial Officer	6,794	Less than 1%
Peter E. Salas (10)	Director; Chairman of the Board	441,531	49.6%
Cary V. Sorensen (11)	Vice President; General Counsel; Secretary	1,969	Less than 1%
Richard M. Thon (12)	Director	2,708	Less than 1%
All Officers and Directors as a group (13)		458,368	51.5%

(6) Unless otherwise stated, all shares of common stock are directly held with sole voting and dispositive power. The shares set forth in the table are as of December 31, 2020 and have been adjusted to reflect the impact of the 1 for 12 stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.

(7) Calculated pursuant to Rule 13d-3(d) under the Securities Exchange Act of 1934 based upon 890,420 shares of common stock being outstanding as of December 31, 2020.  Shares not outstanding that are subject to options or warrants exercisable by the holder thereof within 60 days of December 31, 2020 are deemed outstanding for the purposes of calculating the number and percentage owned by such stockholder, but not deemed outstanding for the purpose of calculating the percentage of any other person.  Unless otherwise noted, all shares listed as beneficially owned by a stockholder are actually outstanding.

(8) Consists of 5,367 shares held directly.

(9) Consists of 6,794 shares held directly.

(10) Consists of directly of 844 shares held individually, and 440,687 shares held directly by Dolphin Offshore Partners, L.P. (“Dolphin”).  Peter E. Salas is the sole shareholder of and controlling person of Dolphin Mgmt. Services, Inc. which is the general partner of Dolphin.

(11) Consists of 1,969 shares held directly.

(12) Consists of 2,708 shares held directly.

(13) Consists of 17,681 shares held directly by directors and management, 440,687 shares held by Dolphin.

Change in Control

On February 25, 2021, the stockholders of the Company approved an Agreement and Plan of Merger which provided for the merger of the Company with Riley Exploration – Permian, LLC (“Riley”). This merger was successfully completed on February 26, 2021.  In connection with the merger, Tengasco changed its name to Riley Exploration Permian, Inc. As a result of this merger, there are no former Tengasco shareholders that own 5% or more of the Company as of February 26, 2021.

39

Equity Compensation Plan Information

The following table sets forth information regarding the Company’s equity compensation plans as of December 31, 2020.

Plan Category	Number of securities to be issued upon exercise of outstanding options, warrants and rights(a)		Weighted-average exercise price of outstanding, options, warrants and rights(b)		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approve by security holders 14		104	$	14.40		21,119
Equity compensation plans not approved by security holders		—		—		—
Total		104	$	14.40		21,119

(14) Refers to Tengasco, Inc. 2018 Stock Incentive Plan (the “2018 Plan”) which was adopted to provide an incentive to key employees, officers, directors and consultants of the Company and its present and future subsidiary corporations, and to offer an additional inducement in obtaining the services of such individuals.  The 2018 Plan contains the same substantive terms of the Company’s previous stock incentive plan adopted in October, 2000 and as thereafter amended until its expiration on January 10, 2018.  The 2018 Plan provided an aggregate number of shares for which shares, options, and stock appreciation rights may be issued under the 2018 Plan equal to the number of shares that were available in the previous plan upon its expiration.  The 2018 Plan was approved by a majority of the Company’s shareholders acting on written consent and the shares thereunder were subject to Registration Statement on Form S-8 filed August 27, 2018.  At the shareholder meeting dated February 25, 2021, the shareholders approved an adopted the Riley Exploration Permian, Inc. Long Term Incentive Plan.  The shares and prices set forth in the table above have been adjusted to reflect the impact of the 1 for 12 stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Certain Transactions

One transaction of the type described above was entered into in 2007 but has expired by its own terms.  On December 18, 2007, the Company entered into a Management Agreement with Hoactzin to manage on behalf of Hoactzin all of its working interest in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As part of the consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or workover activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement.  The Management Agreement expired on December 18, 2012.

The Company entered into a transition agreement with Hoactzin whereby the Company will no longer perform operations, but would administratively assist Hoactzin in becoming operator of record of these wells and administratively assist Hoactzin in the transfer of the corresponding bonds from the Company to Hoactzin.  This assistance was solely related to signing the necessary documents to effectuate this transition.  By the terms of the transition agreement, Hoactzin and its controlling member agreed to indemnify the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company was the operator of record on certain of these wells.

During the second quarter of 2015, the Company received from Hoactzin a copy of an internal analysis prepared by Hoactzin setting out certain issues that Hoactzin may consider to form the basis of operational and other claims against the Company primarily under the Management Agreement.  No claim was made by Hoactzin on its issues and the Company’s position is that all such issues are without merit and any claims thereon are now barred by applicable statutes of limitation.

40

Director Independence

The Rules of the NYSE American (the “NYSE American Rules”) of which the Company is a member require that an issuer, such as the Company, which is a Smaller Reporting Company pursuant to Regulation S-K Item 10(f)(1), maintain a board of directors of which at least one-half of the members are independent in that they are not officers of the Company and are free of any relationship that would interfere with the exercise of their independent judgment. The NYSE American Rules also require that as a Smaller Reporting Company, the Company’s Board of Directors’ Audit Committee be comprised of at least two members all of whom qualify as independent under the criteria set forth in Rule 10 A-3 of the Securities Exchange Act of 1934 and NYSE American Rule 803(b)(2)(c).   Prior to the completion of the Merger Transaction with Riley on February 26, 2021, the then Board of Directors has determined that the Company’s directors, Matthew K. Behrent, and Richard M. Thon, are independent as defined by the NYSE American Rules, and that  Matthew K. Behrent and Richard M. Thon are also independent as defined by Section 10A(m)(3) of the Securities Exchange Act of 1934 and the rules and regulations of the Securities and Exchange Commission; and that none of these directors have any relationship which would interfere with the exercise of his independent judgment in carrying out his responsibilities as a director.  In reaching its determination, the Board of Directors reviewed certain categorical independence standards to provide assistance in the determination of director independence. The categorical standards are set forth below and provide that a director will not qualify as an independent director under the NYSE American Rules if:

The Director is, or has been during the last three years, an employee or an officer of the Company or any of its affiliates;

The Director has received, or has an immediate family member ¹⁸ who has received, during any twelve consecutive months in the last three years any compensation from the Company in excess of $120,000, other than compensation for service on the Board of Directors, compensation to an immediate family member who is an employee of the Company other than an executive officer, compensation received as an interim executive officer or benefits under a tax-qualified retirement plan, or non-discretionary compensation;

The Director is a member of the immediate family of an individual who is, or has been in any of the past three years, employed by the Company or any of its affiliates as an executive officer;

The Director, or an immediate family member, is a partner in, or controlling shareholder or an executive officer of, any for-profit business organization to which the Company made, or received, payments (other than those arising solely from investments in the Company’s securities) that exceed 5% of the Company’s or business organization’s consolidated gross revenues for that year, or $200,000, whichever is more, in any of the past three years;

The Director, or an immediate family member, is employed as an executive officer of another entity where at any time during the most recent three fiscal years any of the Company’s executives serve on that entity’s compensation committee; or

The Director, or an immediate family member, is a current partner of the Company’s outside auditors, or was a partner or employee of the Company’s outside auditors who worked on the Company’s audit at any time during the past three years.

The following additional categorical standards were employed by the Board in determining whether a director qualified as independent to serve on the Audit Committee and provide that a director will not qualify if:

• The Director directly or indirectly accepts any consulting, advisory, or other compensatory fee from the Company or any of its subsidiaries; or

• The Director is an affiliated person¹⁹ of the Company or any of its subsidiaries.

• The Director participated in the preparation of the Company’s financial statements at any time during the past three years.

The independent members of the Board meet as often as necessary to fulfill their responsibilities, but meet at least annually in executive session without the presence of non-independent directors and management.

(15) Under these categorical standards “immediate family member” includes a person’s spouse, parents, children, siblings, mother-in-law, father-in-law, brother-in-law, sister-in-law, son-in-law, daughter-in-law, and anyone who resides in such person’s home (other than a domestic employee).

(16) For purposes of this categorical standard, an “affiliated person of the Company” means a person that directly or indirectly through intermediaries’ controls, or is controlled by, or is under common control with the Company. A person will not be considered to be in control of the Company, and therefore not an affiliate of the Company, if he is not the beneficial owner, directly or indirectly of more than 10% of any class of voting securities of the Company and he is not an executive officer of the Company.  Executive officers of an affiliate of the Company as well as a director who is also an employee of an affiliate of the Company will be deemed to be affiliates of the Company.

41

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Audit and Non-Audit Fees

The following table presents the fees for professional audit services rendered by the Company’s independent registered public accounting firm, Moss Adams LLP (“Moss Adams”), for the audit of the Company’s annual consolidated financial statements, fees for professional audit services rendered for the quarterly reviews for the fiscal years ended December 31, 2020 and December 31, 2019, and fees associated with Form S-4 and Form S-8 filings.

AUDIT AND NON-AUDIT FEES

	2020		2019
	Moss Adams		Moss Adams
Audit Fees	$	214,204	$	122,063
Audit-Related Fees		—		—
Tax Fees		—		—
All Other Fees		—		—
Total Fees	$	214,204	$	122,063

Audit fees include fees related to the services rendered in connection with the annual audit of the Company’s consolidated financial statements, the quarterly reviews of the Company’s quarterly reports on Form 10-Q and the reviews of and other services related to statutory filings or engagements for the subject fiscal years.

Audit-related fees are for assurance and related services by the principal accountants that are reasonably related to the performance of the audit or review of the Company’s financial statements.

Tax Fees include services for (i) tax compliance, (ii) tax advice, (iii) tax planning and (iv) tax reporting.

All Other Fees includes fees for all other services provided by the principal accountants not covered in the other categories such as litigation support, etc.

All of the 2020 services described above were approved by the Audit Committee pursuant to the SEC rule that requires audit committee pre-approval of audit and non-audit services provided by the Company’s independent auditors. The Audit Committee considered whether the provisions of such services, including non-audit services, by Moss Adams were compatible with maintaining its independence and concluded they were.

42

PART IV.

ITEM 15.
EXHIBITS AND FINANCIAL STATEMENTS SCHEDULES

A. The following documents are filed as part of this Report:

1. Financial Statements:

Consolidated Balance Sheets

Consolidated Statements of Operations

Consolidated Statements of Stockholders’ Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

2. Financial Schedules:

Schedules have been omitted because the information required to be set forth therein is not applicable or is included in the Consolidated Financial Statements or notes thereto.

3. Exhibits.

The following exhibits are filed with, or incorporated by reference into this Report:

Exhibit Index

Exhibit Number	Description
3.1	Amended and Restated Certificate of Incorporation as of March 23, 2016 (Incorporated by reference to Exhibit 3 to registrant’s Report on Form 10-Q for the period ended September 30, 2016 filed November 14, 2016).
3.2	Amended and Restated Bylaws as of November 13, 2014 (Incorporated by reference to Exhibit 3.2 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2014 filed on March 30, 2015).
3.3	Agreement and Plan of Merger of Tengasco, Inc. (a Tennessee corporation with and into Tengasco, Inc., a Delaware corporation dated as of April 15, 2011 (Incorporated by reference to Exhibit B to registrant’s Definitive Proxy Statement pursuant to Schedule 14a filed May 2, 2011).
10.1	Tengasco, Inc. 2018 Incentive Stock Plan (Incorporated by reference to Appendix A to the Registrant’s Information Statement on Schedule 14C filed with the Securities and Exchange Commission on August 27, 2018)
10.2	Amended and Restated Loan Agreement between Tengasco, Inc. and Prosperity Bank, effective March 16, 2017 (Incorporated by reference to Exhibit 10.14 to the registrant’s Annual Report on form 10-K for the year ended December 31, 2017 filed March 30, 2018).
10.6	Management Agreement dated December 18, 2007 between Tengasco, Inc. and Hoactzin Partners, L.P.  (Incorporated by reference to Exhibit 10.20 to the 2007 Form 10-K).
14	Code of Ethics (Incorporated by reference to Exhibit 14 to the registrant’s Annual Report on Form 10-K filed March 30, 2004).
23.1*	Consent of LaRoche Petroleum Consultants, Ltd.
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
32.1*	Certification of Chief Executive Officer 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. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99.1*	Report of LaRoche Petroleum Consultants, Ltd. has been added to the filing for the year ended December 31, 2020
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Definition Linkbase Document
101.LAB*	XBRL Taxonomy Label Linkbase Document
101.PRE*	XBRL Taxonomy Presentation Linkbase Document

* Exhibit filed with this Report

43

SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Dated: March 29, 2021

Riley Exploration Permian, Inc.

(Registrant)

By: s/ Michael J. Rugen

Michael J. Rugen,

Principal Financial Officer and Principal Accounting Officer

Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in their capacities and on the dates indicated.

Signature	Title	Date
s/ Brent Arriaga	Director	March 29, 2021
Brent Arriaga
s/ Bryan H. Lawrence	Director	March 29, 2021
Bryan H. Lawrence
s/ E. Wayne Nordberg	Director	March 29, 2021
E. Wayne Nordberg
s/ Bobby D. Riley	Chairman of the Board and Chief Executive Officer	March 29, 2021
Bobby D. Riley	(Principal Executive Officer)
s/ Michael J. Rugen	Chief Financial Officer and Director	March 29, 2021
Michael J. Rugen	(Principal Financial Officer and Principal Accounting Officer)

44

Riley Exploration Permian, Inc.

and Subsidiaries

Consolidated Financial Statements

Years Ended December 31, 2020, and 2019

Report of  Independent Registered Public Accounting Firm	F-2
Consolidated Financial Statements
Consolidated Balance Sheets	F-5
Consolidated Statements of Operations	F-6
Consolidated Statements of Stockholders’ Equity	F-7
Consolidated Statements of Cash Flows	F-8
Notes to Consolidated Financial Statements	F-9

F-1

Report of Independent Registered Public Accounting Firm

To the Stockholders and the Board of Directors of

Riley Exploration Permian, Inc. (f/k/a Tengasco, Inc.)

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Riley Exploration Permian, Inc. and subsidiaries (f/k/a Tengasco, Inc.) (the Company) as of December 31, 2020 and 2019, the related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2020 and 2019, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

Basis for Opinion

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

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

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

F-2

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Assessment of the impact of estimated oil and natural gas reserves related to proved oil and gas properties on depletion expense and the ceiling test calculation.

Description of the Matter

As discussed in Note 1 to the consolidated financial statements, the Company uses the full-cost method of accounting for its oil and gas properties and estimates depletion of capitalized costs of oil and gas properties using the unit-of-production method based on production and estimates of proved reserves quantities. As discussed in Note 4 and Note 1 to the consolidated financial statements, the Company recorded depletion expense and impairment expense of $569 thousand and $920 thousand, respectively, for the year ended December 31, 2020, and the carrying value of oil and gas properties amounted to approximately $2.9 million as of December 31, 2020. The Company is required to perform a ceiling test calculation on a quarterly basis, and the applicable ceiling is equal to the sum of (1) the present value, discounted at 10%, of future net revenues of proved oil and gas reserves, reduced by the estimated costs of developing these reserves, plus (2) unproved and unevaluated property costs not being amortized, plus (3) the lower of cost or estimated fair value of unproved and unevaluated properties included in the costs being amortized, if any, less (4) any income tax effects related to the properties involved. Estimates of economically recoverable oil and natural gas reserves depend upon a number of factors and assumptions, including quantities of oil and gas that are ultimately recovered, the timing of the recovery of oil and gas reserves, the operating costs incurred, the amount of future development expenditures, and the price received for the production. The Company engages external reserves engineers to independently evaluate its proved oil and gas reserves.

We identified the assessment of the impact of estimated oil and gas reserves related to proved oil and gas properties on both depletion expense and the ceiling test calculation as a critical audit matter. There is a high degree of subjectivity in evaluating the estimate of proved oil and gas reserves, as auditor judgment was required to evaluate the assumptions used by the Company related to forecasted production, development costs, operating costs, and forecasted oil and natural gas prices inclusive of market differentials.

F-3

 How the Critical Audit Matter Was Addressed in the Audit

• We assessed the competence, capabilities, and objectivity of the Company's external reserve engineers engaged by the Company and read their findings.

• We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We also compared the pricing assumptions, including price differentials, used in the reserve engineers' estimate of the proved reserves to publicly available oil and natural gas pricing data. We evaluated the consistency of assumptions used in the reserve engineers' estimate regarding future operating and development costs with historical information.

• We compared the forecasted production volumes assumption used by the Company in the current period to historical production, and we compared the Company's historical production forecasts to actual production volumes to assess the Company's ability to accurately forecast.

• We analyzed the depletion expense calculation for compliance with industry and regulatory standards, validated the inputs used in the calculation, and recalculated it.

• We analyzed the ceiling test impairment calculation for compliance with industry and regulatory standards. In addition, we performed an independent calculation of the ceiling test impairment calculation and compared our results with the Company's results.

/s/ Moss Adams LLP

Denver, Colorado

March 29, 2021

We have served as the Company’s auditor since 2017.

F-4

Riley Exploration Permian, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except per share and share data)

	December 31,
	2020		2019
Assets
Current
Cash and cash equivalents	$	1,561	$	3,055
Accounts receivable		294		557
Inventory		361		415
Prepaid expenses		108		247
Other current assets		4		4
Total current assets		2,328		4,278
Loan fees, net		2		4
Right of use asset - operating leases		42		41
Oil and gas properties, net (full cost accounting method)		2,897		4,385
Other property and equipment, net		102		149
Accounts receivable - noncurrent		—		65
Total assets	$	5,371	$	8,922

Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable – trade	$	218		$	269
Accrued liabilities		202			164
Lease liabilities - operating leases - current		42			41
Lease liabilities - finance leases - current		61			61
Asset retirement obligation - current		78			75
Total current liabilities		601			610
Lease liabilities - finance leases - noncurrent		16			41
Asset retirement obligation - non current		2,039			1,923
Total liabilities		2,656			2,574
Commitments and contingencies (Note 8)
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, $.001 par value: authorized 100,000,000 Shares; 890,420 and 888,231 shares issued and outstanding		1			1
Additional paid in capital		58,318			58,303
Accumulated deficit		(55,604	)		(51,956	)
Total stockholders’ equity		2,715			6,348
Total liabilities and stockholders’ equity	$	5,371		$	8,922

See accompanying Notes to Consolidated Financial Statements

F-5

Riley Exploration Permian, Inc. and Subsidiaries

Consolidated Statements of Operations

(In thousands, except per share and share data)

	Year ended December 31,
	2020			2019
Revenues
Oil and gas properties	$	3,038		$	4,911
Total revenues		3,038			4,911
Cost and expenses
Production costs and taxes		3,104			3,398
Depreciation, depletion, and amortization		644			716
General and administrative		2,187			1,302
Impairment Costs		920			—
Total cost and expenses		6,855			5,416
Net loss from operations		(3,817	)		(505	)
Other income (expense)
Net interest expense		(8	)		(10	)
Gain on sale of assets		11			45
Other income		166			6
Total other income		169			41
Loss from operations before income tax		(3,648	)		(464	)
Deferred income tax benefit		—			28
Net loss	$	(3,648	)	$	(436	)
Net loss per share - basic and fully diluted
Continuing operations	$	(4.10	)	$	(0.49	)
Shares used in computing earnings per share
Basic and fully diluted		889,670			887,612

See accompanying Notes to Consolidated Financial Statements

F-6

Riley Exploration Permian, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity

(In thousands, except per share and share data)

	Common Stock				Paid-in Capital		Accumulated Deficit			Total
	Shares		Amount
Balance, December 31, 2018		886,608	$	1	$	58,286	$	(51,520	)	$	6,767
Net loss		—		—		—		(436	)		(436	)
Compensation expense related to stock issued		1,624		—		17		—			17
Balance, December 31, 2019		888,231	$	1	$	58,303	$	(51,956	)	$	6,348
Net loss		—		—		—		(3,648	)		(3,648	)
Compensation expense related to stock issued		2,137		—		14		—			14
Common stock issued for exercise of options		52		—		1		—			1
Balance, December 31, 2020		890,420	$	1	$	58,318	$	(55,604	)	$	2,715

See accompanying Notes to Consolidated Financial Statements

F-7

Riley Exploration Permian, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)

	Year ended December 31,
	2020			2019
Operating activities
Net loss	$	(3,648	)	$	(436	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities
Depreciation, depletion, and amortization		644			716
Amortization of loan fees-interest expenses		2			5
Accretion of discount on asset retirement obligation		125			132
Gain on asset sales		(11	)		(45	)
Loan Forgiveness - PPP Loan		(166	)		—
Compensation and services paid in stock / stock options		14			17
Impairment		920			—
Changes in assets and liabilities:
Accounts receivable		328			41
Inventory, prepaid expense, and other assets		193			(68	)
Accounts payable		32			63
Accrued liabilities		43			(123	)
Settlement on asset retirement obligations		(25	)		(76	)
Net cash provided by (used in) operating activities		(1,549	)		226
Investing activities
Additions to oil and gas properties		(103	)		(437	)
Proceeds from sale of oil and gas properties		38			56
Additions to other property & equipment		(6	)		(2	)
Proceeds from sale of other property & equipment		—			150
Net cash used in investing activities		(71	)		(233	)
Financing activities
Proceeds from borrowings		166			—
Repayment of borrowings		(41	)		(53	)
Proceeds from exercise of options		1			—
Net cash provided by (used in) financing activities		126			(53	)
Net change in cash and cash equivalents		(1,494	)		(60	)
Cash and cash equivalents, beginning of period		3,055			3,115
Cash and cash equivalents, end of period	$	1,561		$	3,055
Supplemental cash flow information:
Cash interest payments	$	6		$	5
Supplemental non-cash investing and financing activities:
Financed company vehicles	$	53		$	57
Asset retirement obligations incurred	$	—		$	12
Revisions to asset retirement obligations	$	69		$	(187	)
Capital expenditures included in accounts payable and accrued liabilities	$	—		$	88

See accompanying Notes to Consolidated Financial Statements

F-8

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

1. Description of Business and Significant Accounting Policies

On February 25, 2021, the stockholders of the Company approved an Agreement and Plan of Merger which provided for the merger of the Company with Riley Exploration – Permian, LLC (“Riley”). This merger was successfully completed on February 26, 2021.  In connection with the merger, Tengasco has changed its name to Riley Exploration Permian, Inc.  The information in these Notes to Consolidated Financial Statements reflect the Tengasco Inc., prior to the merger with Riley and does not include information related to Riley’s operations.

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.

The Company’s wholly owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owned and operated a pipeline which it constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee.  The Company sold all its pipeline assets on August 16, 2013.

The Company’s wholly owned subsidiary, Manufactured Methane Corporation (“MMC”) operated treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity.  The Company sold all its methane facility assets on January 26, 2018.

Principles of Consolidation

The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).  The consolidated financial statements include the accounts of the Company, and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances.

Use of Estimates

The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies.  We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Revenue Recognition

The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Revenues are recognized when the performance obligations are satisfied and when it transfers control of goods or services 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 them to pick up the crude oil from the storage tanks.  When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized.  The sales 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.  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.

Electricity from the Company’s methane facility was sold on a long-term contract.  There were no specific volumes of electricity that were required to be delivered under this contract.  Electricity passed through sales meters located at the Carter Valley landfill site, at which time control of the electricity transferred to the purchaser, the Company’s contractual obligation was satisfied, and revenues were recognized.  The Company sold its methane facility and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date.  Revenues associated with the methane facility are included in Discontinued Operations. (See Note 5. Discontinued Operations)

F-9

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The Company operates certain salt water disposal wells, some of which accept water from third parties.  The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells.  In some cases, the contract is based on 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 in a given month, the Company has met its contractual obligations and revenues are recognized for that month.

The following table presents the disaggregated revenue by commodity for the years ended December 31, 2020 and 2019 (in thousands):

	Year ended December 31,
	2020		2019
Crude oil	$	3,015		4,884
Saltwater disposal fees		23		27
Total	$	3,038	$	4,911

There were no natural gas imbalances at December 31, 2020 or 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 is carried at lower of cost or net realizable value.  The cost component of the oil inventory is calculated using the average quarterly per barrel cost for the quarter ended December 31, 2020 and December 31, 2019.  During 2020 and 2019, the Company included production costs and taxes in its calculation of estimated cost.  The market component is calculated using the average December 2020 and December 2019 oil sales price for the Company’s Kansas properties.  At December 31, 2020 and December 31, 2019, inventory consisted of the following (in thousands):

	December 31,
	2020		2019
Oil – carried at cost	$	361	$	415
Equipment and materials – carried at net realizable value		—		—
Total inventory	$	361	$	415

Oil and Gas Properties

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 both December 31, 2020 and 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.

F-10

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil 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 cost or estimated  fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down may not be reversed in a later period.  The Company performed its ceiling tests during 2020 and 2019, resulting in an impairment of its oil and gas properties of $920,000 in 2020 and no impairment in 2019.

Asset Retirement Obligation

An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is recorded as “Production costs and taxes” in the Consolidated Statements of Operations.  If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.

Manufactured Methane Facilities

The Manufactured Methane facilities were placed into service in April 2009 and were being depreciated using the straight-line method over the useful life based on the estimated landfill closure date of December 2041.  The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018.

Other Property and Equipment

Other property and equipment is carried at cost.  The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from two to seven years.  Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction occurs.

Stock-Based Compensation

The Company records stock-based compensation to employees based on the estimated fair value of the award at grant date.  We recognize expense on a straight-line basis over the requisite service period. For stock-based compensation that vests immediately, the Company recognizes the entire expense in the quarter in which the stock-based compensation is granted.  The Company recorded compensation expense of $14,000 in 2020 and $17,000 in 2019.

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No allowance was recorded at December 31, 2020 and 2019.  At December 31, 2020 and 2019, accounts receivable consisted of the following (in thousands):

F-11

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

	December 31,
	2020		2019
Revenue	$	292	$	415
Tax		—		65
Joint interest		2		77
Accounts receivable - current	$	294	$	557
Tax - noncurrent	$	—	$	65

At December 31, 2019, the Company recorded a tax related non-current receivable in the amount of $65.  (See Note 12. Income Taxes)

Income Taxes

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

Realization of deferred 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 a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency.  A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated.

The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position.  The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized.

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable.  Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances.

The Company’s primary business activities include oil sales to a limited number of customers in the state of Kansas.  The related trade receivables subject the Company to a concentration of credit risk.  The Company sells a majority of its crude oil primarily to two customers in Kansas.  Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it may have a significant adverse effect on the Company’s results of operations.

Revenue from the top two purchasers accounted for 84.7% and 11.1% of total revenues for year ended December 31, 2020.  Revenue from the top two purchasers accounted for 87.7% and 11.8% of total revenues for year ended December 31, 2019.  As of December 31, 2020 and 2019, two of the Company’s oil purchasers accounted for 96.8% and 86.0%, respectively of accounts receivable, of which one oil purchaser accounted for 83.9% and 76.9%, respectively.

F-12

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Earnings per Common Share

The Company reports basic earnings per common share, which excludes 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 reconciliations of the numerators and denominators of the Company’s basic and diluted earnings per share, (in thousands except for share and per share amounts):

	For the years ended December 31,
	2020			2019
Income (numerator):
Net loss	$	(3,648	)	$	(436	)
Weighted average shares (denominator):
Weighted average shares - basic		889,670			887,612
Dilution effect of share-based compensation, treasury method		—			—
Weighted average shares - dilutive		889,670			887,612
Loss per share – Basic and Dilutive:
Basic	$	(4.10	)	$	(0.49	)
Dilutive	$	(4.10	)	$	(0.49	)

Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter was also excluded from diluted shares as they would have been anti-dilutive (See Note 12. Stock and Stock Options).  In addition, the shares that would be issued to employees and Company directors have also been excluded from this calculation. The number of shares have been adjusted to reflect the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.  (See Note 8. Commitments and Contingencies)

Fair Value of Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payables, accrued liabilities, lease liabilities, and long-term debt approximates fair value as of December 31, 2020 and 2019.

Derivative Financial Instruments

The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production.  The Company does not enter into derivative instruments for speculative trading purposes.  The Company presents the fair value of derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements.  As of December 31, 2020 and 2019, the Company did not have any open derivatives.

2. Recent Accounting Pronouncements

In June 2016, the FASB issued an update that requires changes to the recognition of credit losses on financial instruments not accounted for at fair value through net income, including loans, debt securities, trade receivables, net investments in leases and available-for-sale debt securities. The amended standard broadens the information that an entity must consider in developing its estimate of expected credit losses, requiring an entity to estimate credit losses over the life of an exposure based on historical information, current information and reasonable and supportable forecasts. The guidance is effective for interim and annual periods beginning after December 15, 2019. The Company adopted the update effective January 1, 2020 and the impact was not material to the Consolidated Financial Statements

F-13

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

3. Oil and Gas Properties

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

	December 31,
	2020			2019
Oil and gas properties	$	6,752		$	6,751
Ceiling test impairment	$	(3,855	)	$	—
Oil and gas properties, net of ceiling test impairment	$	2,897		$	6,751
Unevaluated properties		—			—
Accumulated depreciation, depletion and amortization		(2,935	)		(2,366	)
Ceiling test impairment		2,935			—
Accumulated depreciation, depletion and amortization, net of ceiling test impairment		—			(2,366	)
Oil and gas properties, net	$	2,897		$	4,385

During the years ended December 31, 2020 and 2019, the Company recorded depletion expense of $569,000 and $637,000, respectively.

4. Other Property and Equipment

Other property and equipment consisted of the following as of December 31, 2020: (in thousands)

Type	Depreciable  Life	Gross Cost		Accumulated Depreciation		Net Book Value
Vehicles	2-3 yrs		259		157		102
Other	5-7 yrs		83		83		—
Total		$	342	$	240	$	102

Other property and equipment consisted of the following as of December 31, 2019: (in thousands)

Type	Depreciable  Life	Gross Cost		Accumulated Depreciation		Net Book Value
Vehicles	2-3 years		295		146		149
Other	5-7 years		83		83		—
Total		$	378	$	229	$	149

The Company uses the straight-line method of depreciation for other property and equipment.  During each of the years ended December 31, 2020 and 2019, the Company recorded depreciation expense of $75,000 and $79,000, respectively.

5. Long-Term Debt

At December 31, 2020, the Company had a revolving credit facility with Prosperity Bank.  Upon closing the Merger Transaction with Riley on February 26, 2021, the credit facility with Prosperity Bank was terminated.  Other than cash flow from operations, this credit facility has historically been the Company’s primary source to fund working capital and future capital spending.  Under the credit facility, loans and letters of credit were 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 December 31, 2020, the Company’s borrowing base was $3.1 million, subject to a credit limit based on current covenants of approximately $1.442 million.  The credit facility was secured by substantially all of the Company’s producing and non-producing oil and gas properties.  The credit facility included certain covenants with which the Company was required to comply.  At December 31, 2020, these covenants included the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x.  At December 31, 2020, the interest rate on this credit facility was 3.75%.  The Company was in compliance with all covenants as of December 31, 2020 and 2019.

F-14

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The Company had zero borrowings under its revolving credit facility with Prosperity Bank on December 31, 2020 and December 31, 2019.  As the credit facility was terminated on February 26, 2021, no further borrowing base reviews will take place.

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.  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 recorded other income of $166,000 as a result of the PPP loan forgiveness.

6. Lease Liabilities

Effective January 1, 2019, the Company adopted ASU 2016-02 Leases (Topic 842).  We first determine if a contract 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 recognized on a straight-line basis over the lease term.  Short term leases that have an initial term of one year or less are not capitalized unless the Company intends to renew the lease to extend the initial term past one year.

We lease certain office space, a storage yard, and field vehicles to support our operations.  A more detailed description of the Company’s lease types is included below.

Office and Storage Yard

The Company maintains an office to support its corporate operations.  This office agreement is with a third party and was structured with a 39 month initial term and an August 31, 2020 expiration date.  The Company renewed the lease for 12 additional months thereby extending the expiration date to August 31, 2021.  The Company’s corporate office lease is classified as an operating lease.

The Company maintains an office to support its field operations.  This office is with a third party and is on a month-to-month lease.  However, the Company intends to continue to renew this lease for the foreseeable future.  Based on the Company’s intent to renew the lease, the Company is assuming the same lease term as its corporate office lease for calculation of its right of use asset and lease liability.  The Company’s field office lease is classified as an operating lease.

The Company maintains a yard to store certain equipment used in its field operations.  This storage yard agreement is with a third party and is on a month-to-month lease.  However, the Company intends to continue to renew this lease for the foreseeable future.  Based on the Company’s intent to renew the lease, the Company is assuming the same lease term 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.

As a result of the renewal of the corporate office lease, the Company recorded right-of-use assets and liabilities associated with operating leases of approximately $63,000 in 2020.

Field Vehicles

The Company leases certain vehicles from a third party for use in its field operations.  The lease term for each vehicle is based on expected daily use of the vehicles by the field personnel, typically between 18 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.

F-15

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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 for the years December 31, 2020 and 2019 (in thousands):

		For the years ended December 31,
	Statement of Operations Account	2020		2019
Operating lease cost:
	Production costs and taxes	$	13	$	13
	General and administrative		50		49
Total operating lease cost		$	63	$	62
Finance lease cost:
Amortization of right of use assets	Depreciation, depletion, and amortization	$	75	$	79
Interest on lease liabilities	Net interest expense		5		5
Total finance lease cost		$	80	$	84

Supplemental lease related cash flow information for the years December 31, 2020 and 2019 (in thousands):

	For the years ended December 31,
	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	63	$	62
Operating cash flows from finance leases		5		5
Finance cash flows from finance leases	$	41	$	53
Right of use assets obtained in exchange for lease obligations:
Operating leases	$	63	$	98

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

	Balance Sheet as of December 31,
	2020			2019
Operating Leases:
Right of use asset - operating leases	$	42		$	41
Lease liabilities - current	$	42		$	41
Lease liabilities - noncurrent		—			—
Total operating lease liabilities	$	42		$	41
Finance Leases:
Other property and equipment, gross	$	342		$	295
Accumulated depreciation		(240	)		(146	)
Other property and equipment, net	$	102		$	149
Lease liabilities - current	$	61		$	61
Lease liabilities - noncurrent		16			41
Total finance lease liabilities	$	77		$	102

F-16

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Weighted average remaining lease term and discount rate as of December 31, 2020:

	Operating Leases			Finance Leases
Weighted average remaining lease term	0.7 years			0.7 years
Weighted average discount rate		3.75	%		5.30	%

Maturity of lease liabilities as of December 31, 2020 (in thousands):

	Operating Leases			Finance Leases
2021		43			62
2022		—			16
Total lease payments		43			78
Less imputed interest		(1	)		(1	)
Total	$	42		$	77

7. Liquidity

On February 25, 2021, the stockholders of the Company approved an Agreement and Plan of Merger which provided for the merger of the Company with Riley Exploration – Permian, LLC (“Riley”). This merger was successfully completed on February 26, 2021.  During 2021, the Company believes as a result of this merger its revenues as well as 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 in place with Riley at the time of the merger.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

8. Commitments and Contingencies

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 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 through December 31, 2020, the reductions were approximately $430,000.  Of the $430,000, approximately $117,000 will be paid in the Company’s common stock.  The $117,000 value represents approximately 8,000 common share valued at $14.88 per share which represents the closing price on December 31, 2020 (the number of shares and price per share have been adjusted to reflect the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021).  The Company has not accrued any liabilities associated with these compensation reductions.  As of the closing of the Merger Transaction with Riley, the potential reimbursement of this amount and shares are no longer due to the former Tengasco employees.

F-17

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Legal Proceedings

We are involved in various legal proceedings relating to our operations and review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our business, financial position, results of operations or liquidity.

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 of, other persons 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 response to the announcement that Tengasco, Inc. and Riley Exploration – Permian 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 Wilhelm 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 Riley 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.

F-18

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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.  In 2020, the Company recorded a ceiling test impairment of its oil and gas properties.  The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities, lease liabilities, and long-term debt in our balance sheet approximates fair value as of December 31, 2020 and December 31, 2019.

10. Asset Retirement Obligation

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the years ended December 31, 2019 and 2020 (in thousands):

Balance December 31, 2018	$	2,179
Accretion expense		132
Liabilities incurred		12
Liabilities settled		(83	)
Liabilities sold properties		(55	)
Revisions in estimated liabilities		(187	)
Balance December 31, 2019	$	1,998
Accretion expense		125
Liabilities incurred		—
Liabilities settled		(25	)
Liabilities sold properties		(50	)
Revisions in estimated liabilities		69
Balance December 31, 2020	$	2,117

F-19

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The revisions in estimated liabilities resulted from change in timing of wells to be plugged, change in inflation factor, and change in current plugging costs.

11. Stock and Stock Options

In October 2000, the Company approved a Stock Incentive Plan which was effective for a ten-year period commencing on October 25, 2000 and ending on October 24, 2010.  The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to participants under the original Plan was not to exceed 7,000,000. An amendment to the Plan increasing the number of shares that may be issued under the Plan by 3,500,000 shares and extending the Plan for another ten years was approved by the Company’s Board of Directors on February 1, 2008 and approved by the Company’s shareholders at the Annual Meeting of Stockholders held on June 2, 2008.  On March 21, 2016 at a special meeting of the shareholders, the Plan was amended to permit grant of common stock.  Options are not transferable, are exercisable for 3 months after voluntary resignation from the Company, and terminate immediately upon involuntary termination from the Company.  The purchase price of shares subject to this Plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the fair market value of such shares on the date of grant.

On March 21, 2016, the Company’s shareholders approved a 1 for 10 reverse stock split, effective with trading on March 24, 2016.  All share and per share information in the following tables has been adjusted to reflect the impact of this reverse stock split.

In August 2018, the Tengasco, Inc. 2018 Stock Incentive Plan (the “2018 Plan”) was adopted to continue to provide an incentive to key employees, officers, directors, and consultants of the Company and its present and future subsidiary corporations, and to offer an additional inducement in obtaining the services of such individuals.  The 2018 Plan contains the same substantive terms as the Company’s previous stock incentive plan adopted in October 2000 and thereafter amended until its expiration on January 10, 2018.  The 2018 Plan provided an aggregate number of shares for which shares, options, and stock appreciation rights may be issued equal to the number of shares that had been available for issuance in the previous plan upon expiration.  The 2018 Plan was approved by a majority of the Company’s shareholders acting on written consents and the shares thereunder were subject to Registration Statement on Form S-8 filed August 27, 2018.

At the shareholder meeting dated February 25, 2021, the shareholders approved an adopted the Riley Exploration Permian, Inc. Long Term Incentive Plan.  Also, on February 25, 2021, the Company’s shareholders approved a 1 for 12 reverse stock split, effective with trading on March 1, 2021.  All share and per share information in the following tables has been adjusted to reflect the impact of this reverse stock split.

The following table summarizes stock option activity in 2020 and 2019:

	2020					2019
	Shares			Weighted Average Exercise Price		Shares			Weighted Average Exercise Price
Outstanding, beginning of year		781		$	26.16		1406		$	38.16
Granted		—		$	—		—		$	—
Exercised		(52	)	$	14.40		—		$	—
Expired/cancelled		(625	)	$	29.16		(625	)	$	53.16
Outstanding, end of year		104		$	14.40		781		$	26.16
Exercisable, end of year		104		$	14.40		781		$	26.16

F-20

The following table summarizes information about stock options outstanding and exercisable at December 31, 2020:

Weighted Average Exercise Price		Options Outstanding (shares)		Weighted Average Remaining Contractual Life (years)		Options Exercisable (shares)
$	14.40		104		—		104
			104				104

On December 31, 2020, Peter Salas exercised approximately 52 options  which represented all of his options then outstanding.  No other options were issued or exercised during 2020 or 2019.  On January 3, 2021, all remaining options outstanding on December 31, 2020 expired.

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-thousandth of a share of the Company’s Series 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 would be limited 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 that a person or group has, become an “Acquiring Person” which is defined 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 the right to acquire, beneficial ownership of 4.95% or more of the Company’s outstanding shares of Common Stock; or a person or group currently owning 4.95% (or more) of the Company’s outstanding shares acquires additional shares of the Company’s stock; subject to certain exceptions; or (ii) the commencement of, or announcement of an intention to commence, 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 on the earlier of March 16, 2020; or a date the Board 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 determined 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 the Merger Agreement pursuant to the terms of the Rights Agreement. On February 25, 2021, the stockholders of the Company approved an Agreement and Plan of Merger which provided for the merger of the Company with Riley Exploration – Permian, LLC. This merger was successfully completed on February 26, 2021, therefore terminating the Rights Agreement and the Rights.

F-21

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

12. Income Taxes

The Company did not have taxable income for the years ended December 31, 2020, and 2019.

A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows (in thousands):

Year Ended December 31, 2020	Total
Statutory rate		21	%
Tax (benefit) expense at statutory rate	$	(764	)
State income tax (benefit) expense		(148	)
Permanent difference		184
Return to provision		1
Stock Compensation Tax Deficit - ASU 2016-09		7
2020 NOL Expiration		334
Net change in deferred tax asset valuation allowance		386
Total income tax provision (benefit)	$	—

Year Ended December 31, 2019	Total
Statutory rate		21	%
Tax (benefit) expense at statutory rate	$	(99	)
State income tax (benefit) expense		321
Permanent difference		—
Return to provision		(40	)
Stock Compensation Tax Deficit - ASU 2016-09		4
2019 NOL Expiration		557
Net change in deferred tax asset valuation allowance		(771	)
Total income tax provision (benefit)	$	(28	)

Management has evaluated the positions taken in connection with the tax provisions and tax compliance for the years included in these financial statements.  The Company believes that all of the positions it has taken will prevail on a more likely than not basis.  As such no disclosure of such positions was deemed necessary.  Management continuously estimates its ability to recognize a deferred tax asset related to prior period net operating loss carry forwards based on its anticipation of the likely timing and adequacy of future net income.

At December 31, 2020, federal net operating loss carryforwards amounted to approximately $35.4 million, of which $30.1 million expires between 2021 and 2037 which can offset 100% of taxable income and $5.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was zero at December 31, 2020 and $65,000 at December 31, 2019.  The Company recorded an allowance on the remaining deferred tax asset at 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.  The Company recorded an allowance on the deferred tax asset at December 31, 2020 primarily due to expected future losses in the near term which would cause cumulative losses being incurred during the 3 year period.  The total valuation allowance at December 31, 2020 was $11.1 million and $10.7 million at December 31, 2019.  The net operating loss information above does not include the impact of the Merger Transaction with Riley.

Our open tax years include all returns filed for 2016 and later.  In addition, any of the Company’s NOLs for tax reporting purposes are still subject to review and adjustment by both the Company and the IRS to the extent such NOLs should be carried forward into an open tax year.

F-22

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Comprehensive tax reform legislation enacted in December 2017, commonly referred to as the Tax Cuts and Jobs Act (the “2017 Tax Act”), made significant changes to U.S. federal income tax laws. The 2017 Tax Act, among other things repealed the corporate AMT for tax years beginning on or after January 1, 2018 and provides for existing alternative minimum tax credit carryovers to be refunded beginning in 2018.  The Company has approximately $130,000 in refundable credits, and it expects that a substantial portion will be refunded between 2019 and 2021.  As 50% of the credit was refunded when we filed the 2019 tax return, this amount is recorded as a current accounts receivable on the Balance Sheet at December 31, 2019, with balance of this refund recorded as a non-current accounts receivable.  In September 2020, the Company received a tax refund of approximately $130,000 associated with the tax related accounts receivable at December 31, 2019.

The Company’s deferred tax assets and liabilities are as follows: (in thousands)

	Year Ended December 31,
	2020			2019
Net deferred tax assets (liabilities):
Net operating loss carryforwards	$	9,596		$	9,119
Oil and gas properties		922			1,054
Property, Plant and Equipment		1			(5	)
Asset retirement obligation		542			500
Tax credits		—			65
Miscellaneous		29			36
Valuation allowance		(11,090	)		(10,704	)
Net deferred tax asset	$	—		$	65

13. Quarterly Data and Share Information (unaudited)

The following tables sets forth for the fiscal periods indicated, selected consolidated financial data (In thousands, except per share data)

Fiscal Year Ended 2020	1st Quarter			2nd Quarter			3rd Quarter			4th Quarter
Revenues	$	963			563		$	765		$	747
Net loss		(527	)		(554	)		(813	)		(1,754	)
Loss per common share	$	(0.60	)	$	(0.60	)	$	(0.96	)	$	(1.92	)

Fiscal Year Ended 2019	1st Quarter			2nd Quarter		3rd Quarter			4th Quarter
Revenues	$	1,171		$	1,390	$	1,215		$	1,135
Net income (loss)		(96	)		9		(182	)		(167	)
Income (loss) per common share	$	(0.12	)	$	0.01	$	(0.24	)	$	(0.12	)

14. Supplemental Oil and Gas Information (unaudited)

Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by LaRoche Petroleum Consultants Ltd.  All of the Company’s reserves were located in the United States.

F-23

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Capitalized Costs Related to Oil and Gas Producing Activities

The table below reflects our capitalized costs related to our oil and gas producing activities at December 31, 2020 and 2019 (in thousands):

	Years Ended December 31,
	2020			2019
Oil and gas properties	$	6,752		$	6,751
Ceiling test impairment	$	(3,855	)	$	—
Oil and gas properties, net of ceiling test impairment	$	2,897		$	6,751
Unevaluated properties		—			—
Accumulated depreciation, depletion and amortization		(2,935	)		(2,366	)
Ceiling test impairment		2,935			—
Accumulated depreciation, depletion and amortization, net of ceiling test impairment		—			(2,366	)
Oil and gas properties, net	$	2,897		$	4,385

Oil and Gas Related Costs

The following table sets forth information concerning costs incurred, including accruals, related to the Company’s oil and gas property acquisition, exploration and development activities (in thousands):

	Years Ended December 31,
	2020		2019
Property acquisitions proved	$	—	$	—
Property acquisitions unproved		6		14
Exploration cost		1		491
Development cost		14		7
Total	$	21	$	512

Results of Operations from Oil and Gas Producing Activities

The following table sets forth the Company’s results of operations from oil and gas producing activities (in thousands):

	Years Ended December 31,
	2020			2019
Revenues	$	3,038		$	4,911
Production costs and taxes		(3,104	)		(3,398	)
Depletion		(569	)		(637	)
Income (loss) from oil and gas producing activities	$	(635	)	$	876

In the presentation above, no deduction has been made for indirect costs such as general corporate overhead or interest expense.  No income taxes are reflected above due to the Company’s operating tax loss carry-forward position.

F-24

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

Estimated Quantities of Oil and Gas Reserves

The following table sets forth the Company’s net proved oil and gas reserves and the changes in net proved oil and gas reserves for the years ended December 31, 2018, 2019 and 2020.  All of the Company’s proved reserves are located in the United States of America.

	Oil (MBbl)			Gas (MMcf)		MBOE
Proved reserves at December 31, 2018		1,094			—		1,094
Revisions of previous estimates		(203	)		—		(203	)
Improved recovery		—			—		—
Purchase of reserves in place		—			—		—
Extensions and discoveries		8			—		8
Production		(94	)		—		(94	)
Sales of reserves in place		(2	)		—		(2	)
Proved reserves at December 31, 2019		803			—		803
Revisions of previous estimates		(200	)		—		(200	)
Improved recovery		—			—		—
Purchase of reserves in place		—			—		—
Extensions and discoveries		—			—		—
Production		(86	)		—		(86	)
Sales of reserves in place		—			—		—
Proved reserves at December 31, 2020		517			—		517
Proved developed reserves at:
December 31, 2018		976			—		976
December 31, 2019		803			—		803
December 31, 2020		517			—		517
Proved undeveloped reserves at:
December 31, 2018		118			—		118
December 31, 2019		—			—		—
December 31, 2020		—			—		—

The Company’s Proved Undeveloped Reserves at December 31, 2018 included 7 locations and no locations at December 31, 2019 and 2020.  During 2019, all Proved Undeveloped locations were removed from the Company’s Proved Reserves primarily due to the low oil prices experienced during 2019.  The price remained low during 2020 resulting in the Company not being able to recognize any Proved Undeveloped locations at December 31, 2020.

F-25

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The following table identifies the Company’s net proved reserve value by category and the respective present values, before income taxes, discounted at 10% as a percentage of total proved reserves (in thousands):

	Year Ended 12/31/2020								Year Ended 12/31/2019								Year Ended 12/31/2018
	Oil			Gas		Total			Oil			Gas		Total			Oil			Gas		Total
Total proved reserves year-end reserve report	$	2,897			—	$	2,897		$	8,365			—	$	8,365		$	13,976			—	$	13,976
Proved developed producing reserves (PDP)	$	2,598			—	$	2,598		$	7,592			—	$	7,592		$	12,534			—	$	12,534
% of PDP reserves to total proved reserves		90	%		—		90	%		91	%		—		91	%		90	%		—		90	%
Proved developed non-producing reserves	$	299			—	$	299		$	773			—	$	773		$	739			—	$	739
% of PDNP reserves to total proved reserves		10	%		—		10	%		9	%		—		9	%		5	%		—		5	%
Proved undeveloped reserves (PUD)	$	—			—	$	—		$	—			—	$	—		$	703			—	$	703
% of PUD reserves to total proved reserves		—			—		—			—			—		—			5	%		—		5	%

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following table (in thousands):

	Years Ended December 31,
	2020			2019			2018
Future cash inflows	$	18,036		$	40,655		$	65,871
Future production costs and taxes		(12,664	)		(24,829	)		(35,877	)
Future development costs		(538	)		(542	)		(2,833	)
Future income tax expenses		—			—			—
Future net cash flows		4,834			15,284			27,161
Discount at 10% for timing of cash flows		(1,937	)		(6,919	)		(13,185	)
Standardized measure of discounted future net cash flows	$	2,897		$	8,365		$	13,976

F-26

Riley Exploration Permian, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

The following are the principal sources of change in the standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves (in thousands):

	Years Ended December 31,
	2020			2019			2018
Balance, beginning of year	$	8,365		$	13,976		$	8,170
Sales, net of production costs and taxes		(210	)		(1,646	)		(2,611	)
Discoveries and extensions, net of costs		—			154			798
Purchase of reserves in place		—			—			143
Sale of reserves in place		—			(26	)		—
Net changes in prices and production costs		(2,893	)		(3,348	)		4,304
Revisions of quantity estimates		(2,353	)		(3,058	)		2,180
Previously estimated development cost incurred during the year		—			—			210
Changes in future development costs		(314	)		1,016			78
Changes in timing and other		(389	)		86			(4	)
Accretion of discount		691			1,211			708
Net change in income taxes		—			—			—
Balance, end of year	$	2,897		$	8,365		$	13,976

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average sales prices along with estimates of the operating costs, production taxes and future development and abandonment cost (less salvage value) necessary to produce such reserves. Future income taxes were calculated by applying the statutory federal and state income tax rates to pre-tax future net cash flows, net of the tax basis of the properties and utilizing available tax loss carryforwards related to oil and gas operations. The oil prices used for December 31, 2020, 2019, and 2018 were $34.87, and $50.65, and $60.21 per barrel of oil, respectively.  The Company’s proved reserves as of December 31, 2020, 2019 and 2018 were measured by using commodity prices based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December.  No deduction has been made for depreciation, depletion, or any indirect cost such as general corporate overhead or interest expense.

16. Subsequent Events

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 Riley. Pursuant to the terms of the Merger Agreement, a business combination between the Registrant and Riley was effected through the merger of Merger Sub with and into Riley, with Riley surviving as the surviving company and as a wholly owned subsidiary of the Registrant (the “Merger” and, collectively with the other transactions described in the Merger Agreement, the “Merger Transaction”). 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, Riley Exploration – Permian, LLC and Riley Permian Operating Company, LLC.  The shares of the Company began trading under the ticker symbol REPX on the NYSE American on March 1, 2021.

In March 2021, the Company entered into an agreement to divest of its Kansas oil and gas properties.  The Company agreed to a sales price of $3.5 million subject to closing adjustment.  The effective date of this transaction will be March 1, 2021.  This agreement is subject to normal due diligence and anticipated to close in early April 2021.  Although anticipated to close in early April 2021, the closing of this divestiture remains subject to various conditions to closing and there can be no assurance that the sale will be completed.

F-27

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We consent to the incorporation by reference in the registration statements on Form S-1, S-3 and Form S-8 of Riley Exploration Permian, Inc. (f/k/a Tengasco, Inc.) to the references to our name as well as to the reference to our third-party report for Tengasco, Inc. which appears in the December 31, 2020 annual report on Form 10-K and/or 10-K/A of  Riley Exploration Permian, Inc. (f/k/a Tengasco, Inc.).

LAROCHE PETROLEUM CONSULTANTS, LTD.
By LPC, Inc. General Partner
By:	/s/ William M. Kazmann
Name:	William M. Kazmann
Title:	President

Richardson, Texas

March 25, 2021

EX-31.1

Exhibit 31.1 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

CERTIFICATION

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Bobby D. Riley, certify that:

1. I have reviewed this Annual Report on Form 10-K of Riley Exploration Permian, Inc. for the year ended December 31, 2020.

2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other information included in this Annual Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Report;

4. The registrant’s certifying officers are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-(f) for the registrant and we have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and

(d) disclosed in this Report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The Registrant’s certifying officers have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated: March 29, 2021

s/ Bobby D. Riley

Bobby D. Riley

Chief Executive Officer

EX-31.2

Exhibit 31.2 Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

CERTIFICATION

PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Michael J. Rugen, certify that:

1. I have reviewed this Annual Report on Form 10-K of Riley Exploration Permian, Inc.for the year ended December 31, 2020.

2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Report;

3. Based on my knowledge, the financial statements, and other information included in this Annual Report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Report;

4. The registrant’s certifying officers are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-(f) for the registrant and we have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this Report based on such evaluation; and

(d) disclosed in this Report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an Annual Report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The Registrant’s certifying officers have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Dated: March 29, 2021

s/ Michael J. Rugen

Michael J. Rugen

Chief Financial Officer

EX-32.1

Exhibit 32.1 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I hereby certify that:

I have reviewed the Annual Report on Form 10-K for the year ended December 31, 2020;

to the best of my knowledge this Annual Report on Form 10-K (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities and Exchange Act of 1934 (15 U.S.C. 78m (a) or 78o (d)); and, (ii) the information contained in this Report fairly present, in all material respects, the financial condition and results of operations of Riley Exploration Permian, Inc. and its subsidiaries during the period covered by this Report.

Dated: March 29, 2021

s/ Bobby D. Riley

Bobby D. Riley

Chief Executive Officer

EX-32.2

Exhibit 32.2 Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED

PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I hereby certify that:

I have reviewed the Annual Report on Form 10-K for the year ended December 31, 2020;

to the best of my knowledge this Annual Report on Form 10-K (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities and Exchange Act of 1934 (15 U.S.C. 78m (a) or 78o (d)); and, (ii) the information contained in this Report fairly present, in all material respects, the financial condition and results of operations of Riley Exploration Permian, Inc. and its subsidiaries during the period covered by this Report.

Dated: March 29, 2021

s/ Michael J. Rugen

Michael J. Rugen

Chief Executive Officer and Chief Financial Officer

EX-99.1

Exhibit 99.1

January 31, 2020

Mr. Michael J. Rugen, CFO

Tengasco, Inc.

6021 S. Syracuse Way, Suite 117

Greenwood Village, CO  80111

Dear Mr. Rugen:

At your request, LaRoche Petroleum Consultants, Ltd. (LPC) has estimated the proved reserves and future cash flow, as of December 31, 2019, to the Tengasco, Inc. (Tengasco) interest in certain properties located in Kansas.  The work for this report was completed as of the date of this letter.  This report was prepared to provide Tengasco with U.S. Securities and Exchange Commission (SEC) compliant reserve estimates.  It is our understanding that the properties evaluated by LPC comprise 100 percent (100%) of Tengasco’s proved reserves.  We believe the assumptions, data, methods, and procedures used in preparing this report, as set out below, are appropriate for the purpose of this report.  This report has been prepared using constant prices and costs and conforms to our understanding of the SEC guidelines, reserves definitions, and applicable financial accounting rules.

Summarized below are LPC’s estimates of net reserves and future net cash flow.  Future net cash flow is after deducting estimated production and ad valorem taxes, operating expenses, and future capital expenditures but before consideration of federal income taxes.  The discounted cash flow values included in this report are intended to represent the time value of money and should not be construed to represent an estimate of fair market value.  We estimate the net reserves and future net cash flow to the Tengasco interest, as of December 31, 2019 to be:

	Net Reserves				Future Net Cash Flow ($)
Category	Oil (barrels)		Gas (Mcf)		Total		Present Worth at 10%
Proved Developed
Producing		766,173		0	$	14,028,548	$	7,591,574
Non-Producing		36,485		0		1,255,069		773,175
Proved Undeveloped		0		0		0		0
Total Proved(1)		802,658		0	$	15,283,617	$	8,364,749

(1) The total proved values above may or may not match those values on the total proved summary page that follows this letter due to rounding by the economics program.

The oil reserves include crude oil and condensate.  Oil reserves are expressed in barrels, which are equivalent to 42 United States gallons.  These properties have never produced commercial volumes of gas.

The estimated reserves and future cash flow shown in this report are for proved developed producing reserves and, for certain properties, proved developed non-producing reserves. Our study indicates there are no proved undeveloped reserves for these properties at this time. This report does not include any value that could be attributed to interests in undeveloped acreage beyond those tracts for which undeveloped reserves have been estimated.

2435 N Central Expressway, Suite 1500  ●  Richardson, TX 75080  ●  Phone (214) 363-3337  ●  Fax (214) 363-1608

Estimates of reserves were prepared using standard geological and engineering methods generally accepted by the petroleum industry.  The reserves in this report have been estimated using deterministic methods.  The method or combination of methods utilized in the evaluation of each reservoir included consideration of the stage of development of the reservoir, quality and completeness of basic data, and production history.  Recovery from various reservoirs and leases was estimated after consideration of the type of energy inherent in the reservoirs, the structural positions of the properties, and reservoir and well performance.  In some instances, comparisons were made to similar properties where more complete data were available.  We have used all methods and procedures that we considered necessary under the circumstances to prepare this report.  We have excluded from our consideration all matters to which the controlling interpretation may be legal or accounting rather than engineering or geoscience.

The estimated reserves and future cash flow amounts in this report are related to hydrocarbon prices.  Historical prices through December 2019 were used in the preparation of this report as required by SEC guidelines; however, actual future prices may vary significantly from the SEC prices.  In addition, future changes in environmental and administrative regulations may significantly affect the ability of Tengasco to produce oil and gas at the projected levels.  Therefore, volumes of reserves actually recovered and amounts of cash flow actually received may differ significantly from the estimated quantities presented in this report.

Benchmark prices used in this report are based on the twelve-month, unweighted arithmetic average of the first day of the month price for the period January through December 2019.  Oil prices used in this report are referenced to a Cushing West Texas Intermediate crude oil price of $55.69 per barrel and are adjusted for gravity, crude quality, transportation fees, and regional price differentials.  This reference price is held constant in accordance with SEC guidelines.  The weighted average price after adjustments over the life of the properties is $50.65 per barrel for oil.

Lease and well operating expenses are based on data obtained from Tengasco.  Expenses for the properties operated by Tengasco include direct lease and field level costs as well as compression costs, marketing expenses, and allocated overhead costs.  Leases and wells operated by others include all direct expenses as well as general and administrative overhead costs allowed under the specific joint operating agreements.  Lease and well operating costs are held constant in accordance with SEC guidelines.

Capital costs and timing of all investments have been provided by Tengasco and are included as required for workovers and production equipment.  Tengasco has represented to us that they have the ability and intent to implement their capital expenditure program as scheduled.  Tengasco’s estimates of the cost to plug and abandon the wells net of salvage value are included and scheduled at the end of the economic life of individual properties.  These costs are also held constant.

LPC made no investigation of possible volume and value imbalances that may have resulted from overdelivery or underdelivery to the Tengasco interest.  Our projections are based on the Tengasco interest receiving its net revenue interest share of estimated future gross oil production.

LaRoche Petroleum Consultants, Ltd.

Technical information necessary for the preparation of the reserve estimates herein was furnished by Tengasco or was obtained from state regulatory agencies and commercially available data sources.  No special tests were obtained to assist in the preparation of this report.  For the purpose of this report, the individual well test and production data as reported by the above sources were accepted as represented together with all other factual data presented by Tengasco including the extent and character of the interest evaluated.

An on-site inspection of the properties has not been performed nor has the mechanical operation or condition of the wells and their related facilities been examined by LPC.  In addition, the costs associated with the continued operation of uneconomic properties are not reflected in the cash flows.

The evaluation of potential environmental liability from the operation and abandonment of the properties is beyond the scope of this report.  In addition, no evaluation was made to determine the degree of operator compliance with current environmental rules, regulations, and reporting requirements.  Therefore, no estimate of the potential economic liability, if any, from environmental concerns is included in the projections presented herein.

The reserves included in this report are estimates only and should not be construed as exact quantities.  They may or may not be recovered; if recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts.  These estimates should be accepted with the understanding that future development, production history, changes in regulations, product prices, and operating expenses would probably cause us to make revisions in subsequent evaluations.  A portion of these reserves are for behind-pipe zones and producing wells that lack sufficient production history to utilize performance-related reserve estimates.  Therefore, these reserves are based on estimates of reservoir volumes and recovery efficiencies along with analogies to similar production.  These reserve estimates are subject to a greater degree of uncertainty than those based on substantial production and pressure data.  It may be necessary to revise these estimates up or down in the future as additional performance data become available.  As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geological data; therefore, our conclusions represent informed professional judgments only, not statements of fact.

The results of our third-party study were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Tengasco.

Tengasco makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act.  Furthermore, Tengasco has certain registration statements filed with the SEC under the 1933 Securities Act into which any subsequently filed Form 10-K is incorporated by reference.  We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8 of Tengasco of the references to our name, as well as to the references to our third-party report for Tengasco which appears in the December 31, 2019 annual report on Form 10-K and/or 10-K/A of Tengasco.  Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Tengasco.

We have provided Tengasco with a digital version of the original signed copy of this report letter.  In the event there are any differences between the digital version included in filings made by Tengasco and the original signed report letter, the original signed report letter shall control and supersede the digital version.

LaRoche Petroleum Consultants, Ltd.

LPC’s technical personnel responsible for preparing this audit meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information promulgated by the Society of Petroleum Engineers.  The technical person primarily responsible for overseeing the preparation of the LPC audit is William M. Kazmann.  Mr. Kazmann is a Professional Engineer licensed in the State of Texas who has 45 years of engineering experience in the oil and gas industry.  He has prepared and overseen preparation of reports for public filings for LPC for the past 24 years. We are independent petroleum engineers, geologists, and geophysicists and are not employed on a contingent basis.  Data pertinent to the audit are maintained on file in our office.

Very truly yours,

LaRoche Petroleum Consultants, Ltd.

State of Texas Registration Number F-1360

By LPC, Inc. General Partner

/s/ Stephen W. Daniel

Stephen W. Daniel

Senior Engineer

/s/ William M. Kazmann

William M. Kazmann, President

Licensed Professional Engineer

State of Texas No. 45012

SWD:ss

19-908

LaRoche Petroleum Consultants, Ltd.

XML

Document And Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Transition Report	false
Amendment Flag	false
Document Period End Date	Dec. 31, 2020
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Entity Registrant Name	RILEY EXPLORATION PERMIAN, INC.
Entity Central Index Key	0001001614
Entity File Number	1-15555
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	87-0267438
Entity Address, Address Line One	29 E. Reno Avenue
Entity Address, Address Line Two	Suite 500
Entity Address, City or Town	Oklahoma City
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73104
City Area Code	405
Local Phone Number	415-8677
Entity Well-known Seasoned Issuer	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Voluntary Filers	No
Entity Public Float		$ 2.9
Current Fiscal Year End Date	--12-31
Entity Small Business	true
Entity Emerging Growth Company	false
Entity Shell Company	false
Trading Symbol	REPX
Title of 12(b) Security	Common Stock
Security Exchange Name	NYSE
Entity Common Stock, Shares Outstanding	890,420
ICFR Auditor Attestation Flag	false

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Current
Cash and cash equivalents	$ 1,561	$ 3,055
Accounts receivable	294	557
Inventory	361	415
Prepaid expenses	108	247
Other current assets	4	4
Total current assets	2,328	4,278
Loan fees, net	2	4
Right of use asset - operating leases	42	41
Oil and gas properties, net (full cost accounting method)	2,897	4,385
Other property and equipment, net	102	149
Accounts receivable - noncurrent		65
Total assets	5,371	8,922
Current liabilities
Accounts payable - trade	218	269
Accrued liabilities	202	164
Lease liabilities - operating leases - current	42	41
Lease liabilities - finance leases - current	61	61
Asset retirement obligation - current	78	75
Total current liabilities	601	610
Lease liabilities - finance leases - noncurrent	16	41
Asset retirement obligation - non current	2,039	1,923
Total liabilities	2,656	2,574
Commitments and contingencies (Note 8)
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, 890,420 and 888,231 shares issued and outstanding	1	1
Additional paid in capital	58,318	58,303
Accumulated deficit	(55,604)	(51,956)
Total stockholders' equity	2,715	6,348
Total liabilities and stockholders' equity	$ 5,371	$ 8,922

XML

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2020	Dec. 31, 2019
Preferred stock, shares authorized	25,000,000	25,000,000
Common stock, par value	$ 0.001	$ 0.001
Common stock, shares authorized	100,000,000	100,000,000
Common stock, shares issued	890,420	888,231
Common stock, shares outstanding	890,420	888,231
Series A Preferred Stock [Member]
Preferred stock, par value	$ 0.0001	$ 0.0001
Preferred stock, shares authorized	10,000	10,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0

XML

Consolidated Statements Of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenues
Revenues	$ 3,038	$ 4,911
Cost and expenses
Production costs and taxes	3,104	3,398
Depreciation, depletion, and amortization	644	716
General and administrative	2,187	1,302
Impairment Costs	920
Total cost and expenses	6,855	5,416
Net loss from operations	(3,817)	(505)
Other income (expense)
Net interest expense	(8)	(10)
Gain on sale of assets	11	45
Other income	166	6
Total other income	169	41
Loss from operations before income tax	(3,648)	(464)
Deferred income tax benefit		28
Net loss	$ (3,648)	$ (436)
Net loss per share - basic and fully diluted
Continuing operations	$ (4.10)	$ (0.49)
Shares used in computing earnings per share
Basic and fully diluted	889,670	887,612
Oil And Gas Properties Revenue [Member]
Revenues
Revenues	$ 3,038	$ 4,911

XML

Consolidated Statements Of Stockholders' Equity - USD ($) $ in Thousands	Common Stock [Member]	Paid-In Capital [Member]	Accumulated Deficit [Member]	Total
Balance, value at Dec. 31, 2018	$ 1	$ 58,286	$ (51,520)	$ 6,767
Balance, shares at Dec. 31, 2018	886,608
Net loss			(436)	(436)
Compensation expense related to stock issued		17		$ 17
Compensation expense related to stock issued, shares	1,624
Balance, shares at Dec. 31, 2019	888,231			888,231
Balance, value at Dec. 31, 2019	$ 1	58,303	(51,956)	$ 6,348
Net loss			(3,648)	(3,648)
Compensation expense related to stock issued		14		14
Compensation expense related to stock issued, shares	2,137
Common stock issued for exercise of options, value		1		$ 1
Common stock issued for exercise of options, shares	52			52
Balance, shares at Dec. 31, 2020	890,420			890,420
Balance, value at Dec. 31, 2020	$ 1	$ 58,318	$ (55,604)	$ 2,715

XML

Consolidated Statements Of Cash Flows - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Operating activities
Net loss	$ (3,648,000)	$ (436,000)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation, depletion, and amortization	644,000	716,000
Amortization of loan fees-interest expense	2,000	5,000
Accretion of discount on asset retirement obligation	125,000	132,000
Gain on asset sales	(11,000)	(45,000)
Loan Forgiveness - PPP Loan	(166,000)
Compensation and services paid in stock / stock options	14,000	17,000
Impairment	920,000
Changes in assets and liabilities:
Accounts receivable	328,000	41,000
Inventory, prepaid expenses and other assets	193,000	(68,000)
Accounts payable	32,000	63,000
Accrued liabilities	43,000	(123,000)
Settlement on asset retirement obligation	(25,000)	(76,000)
Net cash provided by (used in) operating activities	(1,549,000)	226,000
Investing activities
Additions to oil and gas properties	(103,000)	(437,000)
Proceeds from sale of oil and gas properties	38,000	56,000
Additions to other property and equipment	(6,000)	(2,000)
Proceeds from sale of other property and equipment		150,000
Net cash used in investing activities	(71,000)	(233,000)
Financing activities
Proceeds from borrowings	166,000
Repayments of borrowings	(41,000)	(53,000)
Proceeds from exercise of options	1,000
Net cash provided by (used in) financing activities	126,000	(53,000)
Net change in cash and cash equivalents	(1,494,000)	(60,000)
Cash and cash equivalents, beginning of period	3,055,000	3,115,000
Cash and cash equivalents, end of period	1,561,000	3,055,000
Supplemental cash flow information:
Cash interest payments	6,000	5,000
Supplemental non-cash investing and financing activities:
Financed company vehicles	53,000	57,000
Asset retirement obligations incurred		12,000
Revisions to asset retirement obligations	$ 69,000	(187,000)
Capital expenditures included in accounts payable and accrued liabilities		$ 88,000

XML

Description Of Business And Significant Accounting Policies

12 Months Ended

Dec. 31, 2020

Description Of Business And Significant Accounting Policies [Abstract]

Description Of Business And Significant Accounting Policies

1. Description of Business and Significant Accounting Policies

On February 25, 2021, the stockholders of the Company approved an Agreement and Plan of Merger which provided for the merger of the Company with Riley Exploration – Permian, LLC (“Riley”). This merger was successfully completed on February 26, 2021.  In connection with the merger, Tengasco has changed its name to Riley Exploration Permian, Inc.  The information in these Notes to Consolidated Financial Statements reflect the Tengasco Inc., prior to the merger with Riley and does not include information related to Riley’s operations.

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. 

The Company’s wholly owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owned and operated a pipeline which it constructed to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee.  The Company sold all its pipeline assets on August 16, 2013.

The Company’s wholly owned subsidiary, Manufactured Methane Corporation (“MMC”) operated treatment and delivery facilities in Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity.  The Company sold all its methane facility assets on January 26, 2018.

Principles of Consolidation

The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).  The consolidated financial statements include the accounts of the Company, and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances.

Use of Estimates

The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies.  We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Revenue Recognition

The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Revenues are recognized when the performance obligations are satisfied and when it transfers control of goods or services 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 them to pick up the crude oil from the storage tanks.  When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized.  The sales 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.  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.

Electricity from the Company’s methane facility was sold on a long-term contract.  There were no specific volumes of electricity that were required to be delivered under this contract.  Electricity passed through sales meters located at the Carter Valley landfill site, at which time control of the electricity transferred to the purchaser, the Company’s contractual obligation was satisfied, and revenues were recognized.  The Company sold its methane facility and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date.  Revenues associated with the methane facility are included in Discontinued Operations. (See Note 5. Discontinued Operations)

The Company operates certain salt water disposal wells, some of which accept water from third parties.  The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells.  In some cases, the contract is based on 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 in a given month, the Company has met its contractual obligations and revenues are recognized for that month.

The following table presents the disaggregated revenue by commodity for the years ended December 31, 2020 and 2019 (in thousands):  

	Year ended December 31,
	2020		2019
Crude oil	$	3,015		4,884
Saltwater disposal fees		23		27
Total	$	3,038	$	4,911

There were no natural gas imbalances at December 31, 2020 or 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 is carried at lower of cost or net realizable value.  The cost component of the oil inventory is calculated using the average quarterly per barrel cost for the quarter ended December 31, 2020 and December 31, 2019.  During 2020 and 2019, the Company included production costs and taxes in its calculation of estimated cost.  The market component is calculated using the average December 2020 and December 2019 oil sales price for the Company’s Kansas properties.  At December 31, 2020 and December 31, 2019, inventory consisted of the following (in thousands):

	December 31,
	2020		2019
Oil – carried at cost	$	361	$	415
Equipment and materials – carried at net realizable value		—		—
Total inventory	$	361	$	415

Oil and Gas Properties

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 both December 31, 2020 and 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 value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil 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 cost or estimated  fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down may not be reversed in a later period.  The Company performed its ceiling tests during 2020 and 2019, resulting in an impairment of its oil and gas properties of $920,000 in 2020 and no impairment in 2019.

Asset Retirement Obligation

An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is recorded as “Production costs and taxes” in the Consolidated Statements of Operations.  If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.

Manufactured Methane Facilities

The Manufactured Methane facilities were placed into service in April 2009 and were being depreciated using the straight-line method over the useful life based on the estimated landfill closure date of December 2041.  The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018.

Other Property and Equipment

Other property and equipment is carried at cost.  The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from two to seven years.  Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction occurs.

Stock-Based Compensation

The Company records stock-based compensation to employees based on the estimated fair value of the award at grant date.  We recognize expense on a straight-line basis over the requisite service period. For stock-based compensation that vests immediately, the Company recognizes the entire expense in the quarter in which the stock-based compensation is granted.  The Company recorded compensation expense of $14,000 in 2020 and $17,000 in 2019.

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No allowance was recorded at December 31, 2020 and 2019.  At December 31, 2020 and 2019, accounts receivable consisted of the following (in thousands):

	December 31,
	2020		2019
Revenue	$	292	$	415
Tax		—		65
Joint interest		2		77
Accounts receivable - current	$	294	$	557
Tax - noncurrent	$	—	$	65

At December 31, 2019, the Company recorded a tax related non-current receivable in the amount of $65.  (See Note 12. Income Taxes) 

Income Taxes

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

Realization of deferred 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 a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency.  A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated.

The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position.  The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized.

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable.  Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances.

The Company’s primary business activities include oil sales to a limited number of customers in the state of Kansas.  The related trade receivables subject the Company to a concentration of credit risk.  The Company sells a majority of its crude oil primarily to two customers in Kansas.  Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it may have a significant adverse effect on the Company’s results of operations.

Revenue from the top two purchasers accounted for 84.7% and 11.1% of total revenues for year ended December 31, 2020.  Revenue from the top two purchasers accounted for 87.7% and 11.8% of total revenues for year ended December 31, 2019.  As of December 31, 2020 and 2019, two of the Company’s oil purchasers accounted for 96.8% and 86.0%, respectively of accounts receivable, of which one oil purchaser accounted for 83.9% and 76.9%, respectively.

Earnings per Common Share

The Company reports basic earnings per common share, which excludes 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 reconciliations of the numerators and denominators of the Company’s basic and diluted earnings per share, (in thousands except for share and per share amounts):

	For the years ended December 31,
	2020		2019
Income (numerator):
Net loss	$	(3,648)	$	(436)
Weighted average shares (denominator):
Weighted average shares - basic		889,670		887,612
Dilution effect of share-based compensation, treasury method		—		—
Weighted average shares - dilutive		889,670		887,612
Loss per share – Basic and Dilutive:
Basic	$	(4.10)	$	(0.49)
Dilutive	$	(4.10)	$	(0.49)

Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter was also excluded from diluted shares as they would have been anti-dilutive (See Note 12. Stock and Stock Options).  In addition, the shares that would be issued to employees and Company directors have also been excluded from this calculation. The number of shares have been adjusted to reflect the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.  (See Note 8. Commitments and Contingencies)

Fair Value of Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payables, accrued liabilities, lease liabilities, and long-term debt approximates fair value as of December 31, 2020 and 2019.

Derivative Financial Instruments

The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production.  The Company does not enter into derivative instruments for speculative trading purposes.  The Company presents the fair value of derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements.  As of December 31, 2020 and 2019, the Company did not have any open derivatives.

XML

Recent Accounting Pronouncements

12 Months Ended

Dec. 31, 2020

Recent Accounting Pronouncements [Abstract]

Recent Accounting Pronouncements

2. Recent Accounting Pronouncements

In June 2016, the FASB issued an update that requires changes to the recognition of credit losses on financial instruments not accounted for at fair value through net income, including loans, debt securities, trade receivables, net investments in leases and available-for-sale debt securities. The amended standard broadens the information that an entity must consider in developing its estimate of expected credit losses, requiring an entity to estimate credit losses over the life of an exposure based on historical information, current information and reasonable and supportable forecasts. The guidance is effective for interim and annual periods beginning after December 15, 2019. The Company adopted the update effective January 1, 2020 and the impact was not material to the Consolidated Financial Statements

XML

Oil And Gas Properties

12 Months Ended

Dec. 31, 2020

Oil And Gas Properties [Abstract]

Oil And Gas Properties

3. Oil and Gas Properties

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

	December 31,
	2020		2019
Oil and gas properties	$	6,752	$	6,751
Ceiling test impairment	$	(3,855)	$	—
Oil and gas properties, net of ceiling test impairment	$	2,897	$	6,751
Unevaluated properties		—		—
Accumulated depreciation, depletion and amortization		(2,935)		(2,366)
Ceiling test impairment		2,935		—
Accumulated depreciation, depletion and amortization, net of ceiling test impairment		—		(2,366)
Oil and gas properties, net	$	2,897	$	4,385

During the years ended December 31, 2020 and 2019, the Company recorded depletion expense of $569,000 and $637,000, respectively.

XML

Other Property And Equipment

12 Months Ended

Dec. 31, 2020

Other Property And Equipment [Abstract]

Other Property And Equipment

4. Other Property and Equipment

Other property and equipment consisted of the following as of December 31, 2020: (in thousands)

	Depreciable			Accumulated		Net Book
Type	Life	Gross Cost		Depreciation		Value
Vehicles	2-3 yrs		259		157		102
Other	5-7 yrs		83		83		—
Total		$	342	$	240	$	102

Other property and equipment consisted of the following as of December 31, 2019: (in thousands)

	Depreciable			Accumulated		Net Book
Type	Life	Gross Cost		Depreciation		Value
Vehicles	2-3 years		295		146		149
Other	5-7 years		83		83		—
Total		$	378	$	229	$	149

The Company uses the straight-line method of depreciation for other property and equipment.  During each of the years ended December 31, 2020 and 2019, the Company recorded depreciation expense of $75,000 and $79,000, respectively.

XML

Long-Term Debt

12 Months Ended

Dec. 31, 2020

Long-Term Debt [Abstract]

Long-Term Debt

5. Long-Term Debt

At December 31, 2020, the Company had a revolving credit facility with Prosperity Bank.  Upon closing the Merger Transaction with Riley on February 26, 2021, the credit facility with Prosperity Bank was terminated.  Other than cash flow from operations, this credit facility has historically been the Company’s primary source to fund working capital and future capital spending.  Under the credit facility, loans and letters of credit were 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 December 31, 2020, the Company’s borrowing base was $3.1 million, subject to a credit limit based on current covenants of approximately $1.442 million.  The credit facility was secured by substantially all of the Company’s producing and non-producing oil and gas properties.  The credit facility included certain covenants with which the Company was required to comply.  At December 31, 2020, these covenants included the following: (a) Current Ratio > 1:1; (b) Funded Debt to EBITDA < 3.5x; and (c) Interest Coverage > 3.0x.  At December 31, 2020, the interest rate on this credit facility was 3.75%.  The Company was in compliance with all covenants as of December 31, 2020 and 2019.

The Company had zero borrowings under its revolving credit facility with Prosperity Bank on December 31, 2020 and December 31, 2019.  As the credit facility was terminated on February 26, 2021, no further borrowing base reviews will take place.

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.  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 recorded other income of $166,000 as a result of the PPP loan forgiveness.

XML

Lease Liabilities

12 Months Ended

Dec. 31, 2020

Lease Liabilities [Abstract]

Lease Liabilities

6. Lease Liabilities

Effective January 1, 2019, the Company adopted ASU 2016-02 Leases (Topic 842).We first determine if a contract 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 recognized on a straight-line basis over the lease term.  Short term leases that have an initial term of one year or less are not capitalized unless the Company intends to renew the lease to extend the initial term past one year.

We lease certain office space, a storage yard, and field vehicles to support our operations.  A more detailed description of the Company’s lease types is included below.

Office and Storage Yard

The Company maintains an office to support its corporate operations.  This office agreement is with a third party and was structured with a 39 month initial term and an August 31, 2020 expiration date.  The Company renewed the lease for 12 additional months thereby extending the expiration date to August 31, 2021.  The Company’s corporate office lease is classified as an operating lease.

The Company maintains an office to support its field operations.  This office is with a third party and is on a month-to-month lease.  However, the Company intends to continue to renew this lease for the foreseeable future.  Based on the Company’s intent to renew the lease, the Company is assuming the same lease term as its corporate office lease for calculation of its right of use asset and lease liability.  The Company’s field office lease is classified as an operating lease.

The Company maintains a yard to store certain equipment used in its field operations.  This storage yard agreement is with a third party and is on a month-to-month lease.  However, the Company intends to continue to renew this lease for the foreseeable future.  Based on the Company’s intent to renew the lease, the Company is assuming the same lease term 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.

As a result of the renewal of the corporate office lease, the Company recorded right-of-use assets and liabilities associated with operating leases of approximately $63,000 in 2020.

Field Vehicles

The Company leases certain vehicles from a third party for use in its field operations.  The lease term for each vehicle is based on expected daily use of the vehicles by the field personnel, typically between 18 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 for the years December 31, 2020 and 2019 (in thousands):

		For the years ended December 31,
	Statement of Operations Account	2020		2019
Operating lease cost:
	Production costs and taxes	$	13	$	13
	General and administrative		50		49
Total operating lease cost		$	63	$	62
Finance lease cost:
Amortization of right of use assets	Depreciation, depletion, and amortization	$	75	$	79
Interest on lease liabilities	Net interest expense		5		5
Total finance lease cost		$	80	$	84

Supplemental lease related cash flow information for the years December 31, 2020 and 2019 (in thousands):

	For the years ended December 31,
	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	63	$	62
Operating cash flows from finance leases		5		5
Finance cash flows from finance leases	$	41	$	53
Right of use assets obtained in exchange for lease obligations:
Operating leases	$	63	$	98

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

	Balance Sheet as of December 31,
	2020		2019
Operating Leases:
Right of use asset - operating leases	$	42	$	41
Lease liabilities - current	$	42	$	41
Lease liabilities - noncurrent		—		—
Total operating lease liabilities	$	42	$	41
Finance Leases:
Other property and equipment, gross	$	342	$	295
Accumulated depreciation		(240)		(146)
Other property and equipment, net	$	102	$	149
Lease liabilities - current	$	61	$	61
Lease liabilities - noncurrent		16		41
Total finance lease liabilities	$	77	$	102

Weighted average remaining lease term and discount rate as of December 31, 2020:

	Operating Leases		Finance Leases
Weighted average remaining lease term		0.7 years		0.7 years
Weighted average discount rate		3.75%		5.30%

Maturity of lease liabilities as of December 31, 2020 (in thousands):

	Operating Leases		Finance Leases
2021		43		62
2022		—		16
Total lease payments		43		78
Less imputed interest		(1)		(1)
Total	$	42	$	77

XML

Liquidity

12 Months Ended

Dec. 31, 2020

Liquidity [Abstract]

Liquidity

7. Liquidity

On February 25, 2021, the stockholders of the Company approved an Agreement and Plan of Merger which provided for the merger of the Company with Riley Exploration – Permian, LLC (“Riley”). This merger was successfully completed on February 26, 2021.  During 2021, the Company believes as a result of this merger its revenues as well as 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 in place with Riley at the time of the merger.  In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund operations.

XML

Commitments And Contingencies

12 Months Ended

Dec. 31, 2020

Commitments And Contingencies [Abstract]

Commitments And Contingencies

8. Commitments and Contingencies

Cost Reduction Measures

Commencing in the quarter ended March 31, 2015 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 through December 31, 2020, the reductions were approximately $430,000.  Of the $430,000, approximately $117,000 will be paid in the Company’s common stock.  The $117,000 value represents approximately 8,000 common share valued at $14.88 per share which represents the closing price on December 31, 2020 (the number of shares and price per share have been adjusted to reflect the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021).  The Company has not accrued any liabilities associated with these compensation reductions.  As of the closing of the Merger Transaction with Riley, the potential reimbursement of this amount and shares are no longer due to the former Tengasco employees.

Legal Proceedings

We are involved in various legal proceedings relating to our operations and review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. Although the results cannot be known with certainty, we currently believe that the ultimate results of such proceedings will not have a material adverse effect on our business, financial position, results of operations or liquidity.

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 of, other persons 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 response to the announcement that Tengasco, Inc. and Riley Exploration – Permian 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 Wilhelm 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 Riley 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.

XML

Fair Value Measurements

12 Months Ended

Dec. 31, 2020

Fair Value Measurements [Abstract]

Fair Value Measurements

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.  In 2020, the Company recorded a ceiling test impairment of its oil and gas properties.  The carrying amounts of other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities, lease liabilities, and long-term debt in our balance sheet approximates fair value as of December 31, 2020 and December 31, 2019.

XML

Asset Retirement Obligation

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation

10. Asset Retirement Obligation

Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the years ended December 31, 2019 and 2020 (in thousands):

Balance December 31, 2018	$	2,179
Accretion expense		132
Liabilities incurred		12
Liabilities settled		(83)
Liabilities sold properties		(55)
Revisions in estimated liabilities		(187)
Balance December 31, 2019	$	1,998
Accretion expense		125
Liabilities incurred		—
Liabilities settled		(25)
Liabilities sold properties		(50)
Revisions in estimated liabilities		69
Balance December 31, 2020	$	2,117

The revisions in estimated liabilities resulted from change in timing of wells to be plugged, change in inflation factor, and change in current plugging costs.

XML

Stock And Stock Options

12 Months Ended

Dec. 31, 2020

Stock And Stock Options [Abstract]

Stock And Stock Options

11.Stock and Stock Options

In October 2000, the Company approved a Stock Incentive Plan which was effective for a ten-year period commencing on October 25, 2000 and ending on October 24, 2010.  The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to participants under the original Plan was not to exceed 7,000,000. An amendment to the Plan increasing the number of shares that may be issued under the Plan by 3,500,000 shares and extending the Plan for another ten years was approved by the Company’s Board of Directors on February 1, 2008 and approved by the Company’s shareholders at the Annual Meeting of Stockholders held on June 2, 2008.  On March 21, 2016 at a special meeting of the shareholders, the Plan was amended to permit grant of common stock.  Options are not transferable, are exercisable for 3 months after voluntary resignation from the Company, and terminate immediately upon involuntary termination from the Company.  The purchase price of shares subject to this Plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the fair market value of such shares on the date of grant.

On March 21, 2016, the Company’s shareholders approved a 1 for 10 reverse stock split, effective with trading on March 24, 2016.  All share and per share information in the following tables has been adjusted to reflect the impact of this reverse stock split.

In August 2018, the Tengasco, Inc. 2018 Stock Incentive Plan (the “2018 Plan”) was adopted to continue to provide an incentive to key employees, officers, directors, and consultants of the Company and its present and future subsidiary corporations, and to offer an additional inducement in obtaining the services of such individuals.  The 2018 Plan contains the same substantive terms as the Company’s previous stock incentive plan adopted in October 2000 and thereafter amended until its expiration on January 10, 2018.  The 2018 Plan provided an aggregate number of shares for which shares, options, and stock appreciation rights may be issued equal to the number of shares that had been available for issuance in the previous plan upon expiration.  The 2018 Plan was approved by a majority of the Company’s shareholders acting on written consents and the shares thereunder were subject to Registration Statement on Form S-8 filed August 27, 2018.

At the shareholder meeting dated February 25, 2021, the shareholders approved an adopted the Riley Exploration Permian, Inc. Long Term Incentive Plan.  Also, on February 25, 2021, the Company’s shareholders approved a 1 for 12 reverse stock split, effective with trading on March 1, 2021.  All share and per share information in the following tables has been adjusted to reflect the impact of this reverse stock split.

The following table summarizes stock option activity in 2020 and 2019:

	2020			2019
		Weighted			Weighted
		Average			Average
		Exercise			Exercise
	Shares	Price		Shares	Price
Outstanding, beginning of year	781	$	26.16	1406	$	38.16
Granted	—	$	—	—	$	—
Exercised	(52)	$	14.40	—	$	—
Expired/cancelled	(625)	$	29.16	(625)	$	53.16
Outstanding, end of year	104	$	14.40	781	$	26.16
Exercisable, end of year	104	$	14.40	781	$	26.16

The following table summarizes information about stock options outstanding and exercisable at December 31, 2020:

Weighted Average Exercise Price		Options Outstanding (shares)	Weighted Average Remaining Contractual Life (years)	Options Exercisable (shares)
$	14.40	104	—	104
		104		104

On December 31, 2020, Peter Salas exercised approximately 52 options  which represented all of his options then outstanding.  No other options were issued or exercised during 2020 or 2019.  On January 3, 2021, all remaining options outstanding on December 31, 2020 expired.

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-thousandth of a share of the Company’s Series 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 would be limited 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 that a person or group has, become an “Acquiring Person” which is defined 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 the right to acquire, beneficial ownership of 4.95% or more of the Company’s outstanding shares of Common Stock; or a person or group currently owning 4.95% (or more) of the Company’s outstanding shares acquires additional shares of the Company’s stock; subject to certain exceptions; or (ii) the commencement of, or announcement of an intention to commence, 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 on the earlier of March 16, 2020; or a date the Board 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 determined 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 the Merger Agreement pursuant to the terms of the Rights Agreement.On February 25, 2021, the stockholders of the Company approved an Agreement and Plan of Merger which provided for the merger of the Company with Riley Exploration – Permian, LLC. This merger was successfully completed on February 26, 2021, therefore terminating the Rights Agreement and the Rights.

XML

Income Taxes

12 Months Ended

Dec. 31, 2020

Income Taxes [Abstract]

Income Taxes

12. Income Taxes

The Company did not have taxable income for the years ended December 31, 2020, and 2019.

A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows (in thousands):

Year Ended December 31, 2020	Total
Statutory rate		21	%
Tax (benefit) expense at statutory rate	$	(764)
State income tax (benefit) expense		(148)
Permanent difference		184
Return to provision		1
Stock Compensation Tax Deficit - ASU 2016-09		7
2020 NOL Expiration		334
Net change in deferred tax asset valuation allowance		386
Total income tax provision (benefit)	$	—

Year Ended December 31, 2019	Total
Statutory rate		21	%
Tax (benefit) expense at statutory rate	$	(99)
State income tax (benefit) expense		321
Permanent difference		—
Return to provision		(40)
Stock Compensation Tax Deficit - ASU 2016-09		4
2019 NOL Expiration		557
Net change in deferred tax asset valuation allowance		(771)
Total income tax provision (benefit)	$	(28)

Management has evaluated the positions taken in connection with the tax provisions and tax compliance for the years included in these financial statements.  The Company believes that all of the positions it has taken will prevail on a more likely than not basis.  As such no disclosure of such positions was deemed necessary.  Management continuously estimates its ability to recognize a deferred tax asset related to prior period net operating loss carry forwards based on its anticipation of the likely timing and adequacy of future net income.

At December 31, 2020, federal net operating loss carryforwards amounted to approximately $35.4 million, of which $30.1 million expires between 2021 and 2037 which can offset 100% of taxable income and $5.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was zero at December 31, 2020 and $65,000 at December 31, 2019.  The Company recorded an allowance on the remaining deferred tax asset at 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.  The Company recorded an allowance on the deferred tax asset at December 31, 2020 primarily due to expected future losses in the near term which would cause cumulative losses being incurred during the 3 year period.  The total valuation allowance at December 31, 2020 was $11.1 million and $10.7 million at December 31, 2019.  The net operating loss information above does not include the impact of the Merger Transaction with Riley.

Our open tax years include all returns filed for 2016 and later.  In addition, any of the Company’s NOLs for tax reporting purposes are still subject to review and adjustment by both the Company and the IRS to the extent such NOLs should be carried forward into an open tax year.

Comprehensive tax reform legislation enacted in December 2017, commonly referred to as the Tax Cuts and Jobs Act (the “2017 Tax Act”), made significant changes to U.S. federal income tax laws. The 2017 Tax Act, among other things repealed the corporate AMT for tax years beginning on or after January 1, 2018 and provides for existing alternative minimum tax credit carryovers to be refunded beginning in 2018.  The Company has approximately $130,000 in refundable credits, and it expects that a substantial portion will be refunded between 2019 and 2021.  As 50% of the credit was refunded when we filed the 2019 tax return, this amount is recorded as a current accounts receivable on the Balance Sheet at December 31, 2019, with balance of this refund recorded as a non-current accounts receivable. In September 2020, the Company received a tax refund of approximately $130,000 associated with the tax related accounts receivable at December 31, 2019. 

The Company’s deferred tax assets and liabilities are as follows: (in thousands)

	Year Ended December 31,
	2020		2019
Net deferred tax assets (liabilities):
Net operating loss carryforwards	$	9,596	$	9,119
Oil and gas properties		922		1,054
Property, Plant and Equipment		1		(5)
Asset retirement obligation		542		500
Tax credits		—		65
Miscellaneous		29		36
Valuation allowance		(11,090)		(10,704)
Net deferred tax asset	$	—	$	65

XML

Quarterly Data And Share Information

12 Months Ended

Dec. 31, 2020

Quarterly Data And Share Information [Abstract]

Quarterly Data And Share Information

13. Quarterly Data and Share Information (unaudited)

The following tables sets forth for the fiscal periods indicated, selected consolidated financial data (In thousands, except per share data)

Fiscal Year Ended 2020	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
Revenues	$	963		563	$	765	$	747
Net loss		(527)		(554)		(813)		(1,754)
Loss per common share	$	(0.60)	$	(0.60)	$	(0.96)	$	(1.92)

Fiscal Year Ended 2019	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
Revenues	$	1,171	$	1,390	$	1,215	$	1,135
Net income (loss)		(96)		9		(182)		(167)
Income (loss) per common share	$	(0.12)	$	0.01	$	(0.24)	$	(0.12)

XML

Supplemental Oil And Gas Information

12 Months Ended

Dec. 31, 2020

Supplemental Oil And Gas Information [Abstract]

Supplemental Oil And Gas Information

14. Supplemental Oil and Gas Information (unaudited)

Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by LaRoche Petroleum Consultants Ltd.  All of the Company’s reserves were located in the United States.

Capitalized Costs Related to Oil and Gas Producing Activities

The table below reflects our capitalized costs related to our oil and gas producing activities at December 31, 2020 and 2019 (in thousands):

	Years Ended December 31,
	2020		2019
Oil and gas properties	$	6,752	$	6,751
Ceiling test impairment	$	(3,855)	$	—
Oil and gas properties, net of ceiling test impairment	$	2,897	$	6,751
Unevaluated properties		—		—
Accumulated depreciation, depletion and amortization		(2,935)		(2,366)
Ceiling test impairment		2,935		—
Accumulated depreciation, depletion and amortization, net of ceiling test impairment		—		(2,366)
Oil and gas properties, net	$	2,897	$	4,385

Oil and Gas Related Costs

The following table sets forth information concerning costs incurred, including accruals, related to the Company’s oil and gas property acquisition, exploration and development activities (in thousands):

	Years Ended December 31,
	2020		2019
Property acquisitions proved	$	—	$	—
Property acquisitions unproved		6		14
Exploration cost		1		491
Development cost		14		7
Total	$	21	$	512

Results of Operations from Oil and Gas Producing Activities

The following table sets forth the Company’s results of operations from oil and gas producing activities (in thousands):

	Years Ended December 31,
	2020		2019
Revenues	$	3,038	$	4,911
Production costs and taxes		(3,104)		(3,398)
Depletion		(569)		(637)
Income (loss) from oil and gas producing activities	$	(635)	$	876

In the presentation above, no deduction has been made for indirect costs such as general corporate overhead or interest expense.  No income taxes are reflected above due to the Company’s operating tax loss carry-forward position.

Estimated Quantities of Oil and Gas Reserves

The following table sets forth the Company’s net proved oil and gas reserves and the changes in net proved oil and gas reserves for the years ended December 31, 2018, 2019 and 2020.  All of the Company’s proved reserves are located in the United States of America.

	Oil (MBbl)	Gas (MMcf)	MBOE
Proved reserves at December 31, 2018	1,094	—	1,094
Revisions of previous estimates	(203)	—	(203)
Improved recovery	—	—	—
Purchase of reserves in place	—	—	—
Extensions and discoveries	8	—	8
Production	(94)	—	(94)
Sales of reserves in place	(2)	—	(2)
Proved reserves at December 31, 2019	803	—	803
Revisions of previous estimates	(200)	—	(200)
Improved recovery	—	—	—
Purchase of reserves in place	—	—	—
Extensions and discoveries	—	—	—
Production	(86)	—	(86)
Sales of reserves in place	—	—	—
Proved reserves at December 31, 2020	517	—	517
Proved developed reserves at:
December 31, 2018	976	—	976
December 31, 2019	803	—	803
December 31, 2020	517	—	517
Proved undeveloped reserves at:
December 31, 2018	118	—	118
December 31, 2019	—	—	—
December 31, 2020	—	—	—

The Company’s Proved Undeveloped Reserves at December 31, 2018 included 7 locations and no locations at December 31, 2019 and 2020.  During 2019, all Proved Undeveloped locations were removed from the Company’s Proved Reserves primarily due to the low oil prices experienced during 2019.  The price remained low during 2020 resulting in the Company not being able to recognize any Proved Undeveloped locations at December 31, 2020.

The following table identifies the Company’s net proved reserve value by category and the respective present values, before income taxes, discounted at 10% as a percentage of total proved reserves (in thousands):

	Year Ended 12/31/2020						Year Ended 12/31/2019						Year Ended 12/31/2018
	Oil		Gas		Total		Oil		Gas		Total		Oil		Gas		Total
Total proved reserves    year-end reserve    report	$	2,897		—	$	2,897	$	8,365		—	$	8,365	$	13,976		—	$	13,976
Proved developed    producing reserves    (PDP)	$	2,598		—	$	2,598	$	7,592		—	$	7,592	$	12,534		—	$	12,534
% of PDP reserves to    total proved reserves		90%		—		90%		91%		—		91%		90%		—		90%
Proved developed non-    producing reserves	$	299		—	$	299	$	773		—	$	773	$	739		—	$	739
% of PDNP reserves to    total proved reserves		10%		—		10%		9%		—		9%		5%		—		5%
Proved undeveloped    reserves (PUD)	$	—		—	$	—	$	—		—	$	—	$	703		—	$	703
% of PUD reserves to    total proved reserves		—		—		—		—		—		—		5%		—		5%

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following table (in thousands):

	Years Ended December 31,
	2020		2019		2018
Future cash inflows	$	18,036	$	40,655	$	65,871
Future production costs and taxes		(12,664)		(24,829)		(35,877)
Future development costs		(538)		(542)		(2,833)
Future income tax expenses		—		—		—
Future net cash flows		4,834		15,284		27,161
Discount at 10% for timing of cash flows		(1,937)		(6,919)		(13,185)
Standardized measure of discounted future net cash flows	$	2,897	$	8,365	$	13,976

The following are the principal sources of change in the standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves (in thousands):

	Years Ended December 31,
	2020		2019		2018
Balance, beginning of year	$	8,365	$	13,976	$	8,170
Sales, net of production costs and taxes		(210)		(1,646)		(2,611)
Discoveries and extensions, net of costs		—		154		798
Purchase of reserves in place		—		—		143
Sale of reserves in place		—		(26)		—
Net changes in prices and production costs		(2,893)		(3,348)		4,304
Revisions of quantity estimates		(2,353)		(3,058)		2,180
Previously estimated development cost incurred during the year		—		—		210
Changes in future development costs		(314)		1,016		78
Changes in timing and other		(389)		86		(4)
Accretion of discount		691		1,211		708
Net change in income taxes		—		—		—
Balance, end of year	$	2,897	$	8,365	$	13,976

Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using average sales prices along with estimates of the operating costs, production taxes and future development and abandonment cost (less salvage value) necessary to produce such reserves. Future income taxes were calculated by applying the statutory federal and state income tax rates to pre-tax future net cash flows, net of the tax basis of the properties and utilizing available tax loss carryforwards related to oil and gas operations. The oil prices used for December 31, 2020, 2019, and 2018 were $34.87, and $50.65, and $60.21 per barrel of oil, respectively.  The Company’s proved reserves as of December 31, 2020, 2019 and 2018 were measured by using commodity prices based on the twelve month unweighted arithmetic average of the first day of the month price for the period January through December.  No deduction has been made for depreciation, depletion, or any indirect cost such as general corporate overhead or interest expense.

XML

Subsequent Events

12 Months Ended

Dec. 31, 2020

Subsequent Events [Abstract]

Subsequent Events

16. Subsequent Events

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 Riley. Pursuant to the terms of the Merger Agreement, a business combination between the Registrant and Riley was effected through the merger of Merger Sub with and into Riley, with Riley surviving as the surviving company and as a wholly owned subsidiary of the Registrant (the “Merger” and, collectively with the other transactions described in the Merger Agreement, the “Merger Transaction”). 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, Riley Exploration – Permian, LLC and Riley Permian Operating Company, LLC.  The shares of the Company began trading under the ticker symbol REPX on the NYSE American on March 1, 2021.

In March 2021, the Company entered into an agreement to divest of its Kansas oil and gas properties.  The Company agreed to a sales price of $3.5 million subject to closing adjustment.  The effective date of this transaction will be March 1, 2021.  This agreement is subject to normal due diligence and anticipated to close in early April 2021.  Although anticipated to close in early April 2021, the closing of this divestiture remains subject to various conditions to closing and there can be no assurance that the sale will be completed.

XML

Description Of Business And Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2020

Description Of Business And Significant Accounting Policies [Abstract]

Principles Of Consolidation

Principles of Consolidation

The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”).  The consolidated financial statements include the accounts of the Company, and its wholly owned subsidiaries after elimination of all significant intercompany transactions and balances.

Use Of Estimates

Use of Estimates

The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods.  Significant estimates include reserve quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based compensation and commitments and contingencies.  We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements are appropriate, actual results could differ from those estimates.

Revenue Recognition

Revenue Recognition

The Company identifies the contracts with each of its customers and the separate performance obligations associated with each of these contracts.  Revenues are recognized when the performance obligations are satisfied and when it transfers control of goods or services 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 them to pick up the crude oil from the storage tanks.  When the purchaser picks up the crude from the storage tanks, control of the crude transfers to the purchaser, the Company’s contractual obligation is satisfied, and revenues are recognized.  The sales 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.  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.

Electricity from the Company’s methane facility was sold on a long-term contract.  There were no specific volumes of electricity that were required to be delivered under this contract.  Electricity passed through sales meters located at the Carter Valley landfill site, at which time control of the electricity transferred to the purchaser, the Company’s contractual obligation was satisfied, and revenues were recognized.  The Company sold its methane facility and generation assets on January 26, 2018 and therefore will not recognize revenues associated with any sales volumes after that date.  Revenues associated with the methane facility are included in Discontinued Operations. (See Note 5. Discontinued Operations)

The Company operates certain salt water disposal wells, some of which accept water from third parties.  The contracts with the third parties primarily require a flat monthly fee for the third parties to dispose water into the wells.  In some cases, the contract is based on 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 in a given month, the Company has met its contractual obligations and revenues are recognized for that month.

The following table presents the disaggregated revenue by commodity for the years ended December 31, 2020 and 2019 (in thousands):  

	Year ended December 31,
	2020		2019
Crude oil	$	3,015		4,884
Saltwater disposal fees		23		27
Total	$	3,038	$	4,911

There were no natural gas imbalances at December 31, 2020 or 2019. 

Cash And Cash Equivalents

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

Inventory consists of crude oil in tanks and is carried at lower of cost or net realizable value.  The cost component of the oil inventory is calculated using the average quarterly per barrel cost for the quarter ended December 31, 2020 and December 31, 2019.  During 2020 and 2019, the Company included production costs and taxes in its calculation of estimated cost.  The market component is calculated using the average December 2020 and December 2019 oil sales price for the Company’s Kansas properties.  At December 31, 2020 and December 31, 2019, inventory consisted of the following (in thousands):

	December 31,
	2020		2019
Oil – carried at cost	$	361	$	415
Equipment and materials – carried at net realizable value		—		—
Total inventory	$	361	$	415

Oil And Gas Properties

Oil and Gas Properties

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 both December 31, 2020 and 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 value of the net capitalized cost of oil and gas properties. This test compares the net capitalized cost (capitalized cost of oil 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 cost or estimated  fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required.  A write-down of the carrying value of the asset is a non-cash charge that reduces earnings in the current period.  Once incurred, a write-down may not be reversed in a later period.  The Company performed its ceiling tests during 2020 and 2019, resulting in an impairment of its oil and gas properties of $920,000 in 2020 and no impairment in 2019.

Asset Retirement Obligation

Asset Retirement Obligation

An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is recorded as “Production costs and taxes” in the Consolidated Statements of Operations.  If the estimated future cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.

Manufactured Methane Facilities

Manufactured Methane Facilities

The Manufactured Methane facilities were placed into service in April 2009 and were being depreciated using the straight-line method over the useful life based on the estimated landfill closure date of December 2041.  The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018.

Other Property And Equipment

Other Property and Equipment

Other property and equipment is carried at cost.  The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from two to seven years.  Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction occurs.

Stock-Based Compensation

Stock-Based Compensation

The Company records stock-based compensation to employees based on the estimated fair value of the award at grant date.  We recognize expense on a straight-line basis over the requisite service period. For stock-based compensation that vests immediately, the Company recognizes the entire expense in the quarter in which the stock-based compensation is granted.  The Company recorded compensation expense of $14,000 in 2020 and $17,000 in 2019.

Accounts Receivable

Accounts Receivable

Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. No allowance was recorded at December 31, 2020 and 2019.  At December 31, 2020 and 2019, accounts receivable consisted of the following (in thousands):

	December 31,
	2020		2019
Revenue	$	292	$	415
Tax		—		65
Joint interest		2		77
Accounts receivable - current	$	294	$	557
Tax - noncurrent	$	—	$	65

At December 31, 2019, the Company recorded a tax related non-current receivable in the amount of $65.  (See Note 12. Income Taxes) 

Income Taxes

Income Taxes

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

Realization of deferred 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 a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.

Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the establishment of a loss contingency.  A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated.

The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax position.  The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized.

Concentration Of Credit Risk

Concentration of Credit Risk

Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable.  Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances.

The Company’s primary business activities include oil sales to a limited number of customers in the state of Kansas.  The related trade receivables subject the Company to a concentration of credit risk.  The Company sells a majority of its crude oil primarily to two customers in Kansas.  Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it may have a significant adverse effect on the Company’s results of operations.

Revenue from the top two purchasers accounted for 84.7% and 11.1% of total revenues for year ended December 31, 2020.  Revenue from the top two purchasers accounted for 87.7% and 11.8% of total revenues for year ended December 31, 2019.  As of December 31, 2020 and 2019, two of the Company’s oil purchasers accounted for 96.8% and 86.0%, respectively of accounts receivable, of which one oil purchaser accounted for 83.9% and 76.9%, respectively.

Earnings Per Common Share

Earnings per Common Share

The Company reports basic earnings per common share, which excludes 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 reconciliations of the numerators and denominators of the Company’s basic and diluted earnings per share, (in thousands except for share and per share amounts):

	For the years ended December 31,
	2020		2019
Income (numerator):
Net loss	$	(3,648)	$	(436)
Weighted average shares (denominator):
Weighted average shares - basic		889,670		887,612
Dilution effect of share-based compensation, treasury method		—		—
Weighted average shares - dilutive		889,670		887,612
Loss per share – Basic and Dilutive:
Basic	$	(4.10)	$	(0.49)
Dilutive	$	(4.10)	$	(0.49)

Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter was also excluded from diluted shares as they would have been anti-dilutive (See Note 12. Stock and Stock Options).  In addition, the shares that would be issued to employees and Company directors have also been excluded from this calculation. The number of shares have been adjusted to reflect the impact of the 1 for 12 reverse stock split approved at the shareholder meeting dated February 25, 2021, effective with trading on March 1, 2021.  (See Note 8. Commitments and Contingencies)

Fair Value Of Financial Instruments

Fair Value of Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payables, accrued liabilities, lease liabilities, and long-term debt approximates fair value as of December 31, 2020 and 2019.

Derivative Financial Instruments

Derivative Financial Instruments

The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production.  The Company does not enter into derivative instruments for speculative trading purposes.  The Company presents the fair value of derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements.  As of December 31, 2020 and 2019, the Company did not have any open derivatives

Reclassifications

.

XML

Description Of Business And Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

Description Of Business And Significant Accounting Policies [Abstract]

Disaggregation Of Revenue

	Year ended December 31,
	2020		2019
Crude oil	$	3,015		4,884
Saltwater disposal fees		23		27
Total	$	3,038	$	4,911

Inventory

	December 31,
	2020		2019
Oil – carried at cost	$	361	$	415
Equipment and materials – carried at net realizable value		—		—
Total inventory	$	361	$	415

Accounts Receivable

	December 31,
	2020		2019
Revenue	$	292	$	415
Tax		—		65
Joint interest		2		77
Accounts receivable - current	$	294	$	557
Tax - noncurrent	$	—	$	65

Reconciliations Of The Numerators And Denominators Of Basic And Diluted Earnings Per Share

	For the years ended December 31,
	2020		2019
Income (numerator):
Net loss	$	(3,648)	$	(436)
Weighted average shares (denominator):
Weighted average shares - basic		889,670		887,612
Dilution effect of share-based compensation, treasury method		—		—
Weighted average shares - dilutive		889,670		887,612
Loss per share – Basic and Dilutive:
Basic	$	(4.10)	$	(0.49)
Dilutive	$	(4.10)	$	(0.49)

XML

Oil And Gas Properties (Tables)

12 Months Ended

Dec. 31, 2020

Oil And Gas Properties [Abstract]

Schedule Of Oil And Gas Properties

	December 31,
	2020		2019
Oil and gas properties	$	6,752	$	6,751
Ceiling test impairment	$	(3,855)	$	—
Oil and gas properties, net of ceiling test impairment	$	2,897	$	6,751
Unevaluated properties		—		—
Accumulated depreciation, depletion and amortization		(2,935)		(2,366)
Ceiling test impairment		2,935		—
Accumulated depreciation, depletion and amortization, net of ceiling test impairment		—		(2,366)
Oil and gas properties, net	$	2,897	$	4,385

XML

Other Property And Equipment (Tables)

12 Months Ended

Dec. 31, 2020

Other Property And Equipment [Abstract]

Schedule Of Other Property And Equipment

Other property and equipment consisted of the following as of December 31, 2020: (in thousands)

	Depreciable			Accumulated		Net Book
Type	Life	Gross Cost		Depreciation		Value
Vehicles	2-3 yrs		259		157		102
Other	5-7 yrs		83		83		—
Total		$	342	$	240	$	102

Other property and equipment consisted of the following as of December 31, 2019: (in thousands)

	Depreciable			Accumulated		Net Book
Type	Life	Gross Cost		Depreciation		Value
Vehicles	2-3 years		295		146		149
Other	5-7 years		83		83		—
Total		$	378	$	229	$	149

XML

Lease Liabilities (Tables)

12 Months Ended

Dec. 31, 2020

Lease Liabilities [Abstract]

Components Of Lease Cost

		For the years ended December 31,
	Statement of Operations Account	2020		2019
Operating lease cost:
	Production costs and taxes	$	13	$	13
	General and administrative		50		49
Total operating lease cost		$	63	$	62
Finance lease cost:
Amortization of right of use assets	Depreciation, depletion, and amortization	$	75	$	79
Interest on lease liabilities	Net interest expense		5		5
Total finance lease cost		$	80	$	84

Supplemental Cash Flow Information Related To Leases

	For the years ended December 31,
	2020		2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	63	$	62
Operating cash flows from finance leases		5		5
Finance cash flows from finance leases	$	41	$	53
Right of use assets obtained in exchange for lease obligations:
Operating leases	$	63	$	98

Supplemental Balance Sheet Information Related To Leases

	Balance Sheet as of December 31,
	2020		2019
Operating Leases:
Right of use asset - operating leases	$	42	$	41
Lease liabilities - current	$	42	$	41
Lease liabilities - noncurrent		—		—
Total operating lease liabilities	$	42	$	41
Finance Leases:
Other property and equipment, gross	$	342	$	295
Accumulated depreciation		(240)		(146)
Other property and equipment, net	$	102	$	149
Lease liabilities - current	$	61	$	61
Lease liabilities - noncurrent		16		41
Total finance lease liabilities	$	77	$	102

Schedule Of Weighted Average Remaining Lease Term And Discount Rate

	Operating Leases		Finance Leases
Weighted average remaining lease term		0.7 years		0.7 years
Weighted average discount rate		3.75%		5.30%

Maturity Analysis For Operating and Finance Lease Liabilities

	Operating Leases		Finance Leases
2021		43		62
2022		—		16
Total lease payments		43		78
Less imputed interest		(1)		(1)
Total	$	42	$	77

XML

Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2020

Asset Retirement Obligation [Abstract]

Asset Retirement Obligation Transactions

Balance December 31, 2018	$	2,179
Accretion expense		132
Liabilities incurred		12
Liabilities settled		(83)
Liabilities sold properties		(55)
Revisions in estimated liabilities		(187)
Balance December 31, 2019	$	1,998
Accretion expense		125
Liabilities incurred		—
Liabilities settled		(25)
Liabilities sold properties		(50)
Revisions in estimated liabilities		69
Balance December 31, 2020	$	2,117

XML

Stock And Stock Options (Tables)

12 Months Ended

Dec. 31, 2020

Stock And Stock Options [Abstract]

Schedule Of Stock Option Activity

	2020			2019
		Weighted			Weighted
		Average			Average
		Exercise			Exercise
	Shares	Price		Shares	Price
Outstanding, beginning of year	781	$	26.16	1406	$	38.16
Granted	—	$	—	—	$	—
Exercised	(52)	$	14.40	—	$	—
Expired/cancelled	(625)	$	29.16	(625)	$	53.16
Outstanding, end of year	104	$	14.40	781	$	26.16
Exercisable, end of year	104	$	14.40	781	$	26.16

Schedule Of Stock Options Outstanding And Exercisable

Weighted Average Exercise Price		Options Outstanding (shares)	Weighted Average Remaining Contractual Life (years)	Options Exercisable (shares)
$	14.40	104	—	104
		104		104

XML

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

Income Taxes [Abstract]

Reconciliation Of The Statutory U.S. Federal Income Tax And The Income Tax Provision

Year Ended December 31, 2020	Total
Statutory rate		21	%
Tax (benefit) expense at statutory rate	$	(764)
State income tax (benefit) expense		(148)
Permanent difference		184
Return to provision		1
Stock Compensation Tax Deficit - ASU 2016-09		7
2020 NOL Expiration		334
Net change in deferred tax asset valuation allowance		386
Total income tax provision (benefit)	$	—

Year Ended December 31, 2019	Total
Statutory rate		21	%
Tax (benefit) expense at statutory rate	$	(99)
State income tax (benefit) expense		321
Permanent difference		—
Return to provision		(40)
Stock Compensation Tax Deficit - ASU 2016-09		4
2019 NOL Expiration		557
Net change in deferred tax asset valuation allowance		(771)
Total income tax provision (benefit)	$	(28)

Schedule Of Deferred Tax Assets And Liabilities

	Year Ended December 31,
	2020		2019
Net deferred tax assets (liabilities):
Net operating loss carryforwards	$	9,596	$	9,119
Oil and gas properties		922		1,054
Property, Plant and Equipment		1		(5)
Asset retirement obligation		542		500
Tax credits		—		65
Miscellaneous		29		36
Valuation allowance		(11,090)		(10,704)
Net deferred tax asset	$	—	$	65

XML

Quarterly Data And Share Information (Tables)

12 Months Ended

Dec. 31, 2020

Quarterly Data And Share Information [Abstract]

Schedule Of Quarterly Data

Fiscal Year Ended 2020	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
Revenues	$	963		563	$	765	$	747
Net loss		(527)		(554)		(813)		(1,754)
Loss per common share	$	(0.60)	$	(0.60)	$	(0.96)	$	(1.92)

Fiscal Year Ended 2019	1st Quarter		2nd Quarter		3rd Quarter		4th Quarter
Revenues	$	1,171	$	1,390	$	1,215	$	1,135
Net income (loss)		(96)		9		(182)		(167)
Income (loss) per common share	$	(0.12)	$	0.01	$	(0.24)	$	(0.12)

XML

Supplemental Oil And Gas Information (Tables)

12 Months Ended

Dec. 31, 2020

Supplemental Oil And Gas Information [Abstract]

Schedule Of Capitalized Costs Related To Oil And Gas Producing Activities

	Years Ended December 31,
	2020		2019
Oil and gas properties	$	6,752	$	6,751
Ceiling test impairment	$	(3,855)	$	—
Oil and gas properties, net of ceiling test impairment	$	2,897	$	6,751
Unevaluated properties		—		—
Accumulated depreciation, depletion and amortization		(2,935)		(2,366)
Ceiling test impairment		2,935		—
Accumulated depreciation, depletion and amortization, net of ceiling test impairment		—		(2,366)
Oil and gas properties, net	$	2,897	$	4,385

Schedule Of Oil And Gas Property Acquisition, Exploration And Development

	Years Ended December 31,
	2020		2019
Property acquisitions proved	$	—	$	—
Property acquisitions unproved		6		14
Exploration cost		1		491
Development cost		14		7
Total	$	21	$	512

Schedule Of Results Of Operations From Oil And Gas Producing Activities

	Years Ended December 31,
	2020		2019
Revenues	$	3,038	$	4,911
Production costs and taxes		(3,104)		(3,398)
Depletion		(569)		(637)
Income (loss) from oil and gas producing activities	$	(635)	$	876

Schedule Of Net Proved Oil And Gas Reserves And The Changes In Net Proved Oil And Gas Reserves

	Oil (MBbl)	Gas (MMcf)	MBOE
Proved reserves at December 31, 2018	1,094	—	1,094
Revisions of previous estimates	(203)	—	(203)
Improved recovery	—	—	—
Purchase of reserves in place	—	—	—
Extensions and discoveries	8	—	8
Production	(94)	—	(94)
Sales of reserves in place	(2)	—	(2)
Proved reserves at December 31, 2019	803	—	803
Revisions of previous estimates	(200)	—	(200)
Improved recovery	—	—	—
Purchase of reserves in place	—	—	—
Extensions and discoveries	—	—	—
Production	(86)	—	(86)
Sales of reserves in place	—	—	—
Proved reserves at December 31, 2020	517	—	517
Proved developed reserves at:
December 31, 2018	976	—	976
December 31, 2019	803	—	803
December 31, 2020	517	—	517
Proved undeveloped reserves at:
December 31, 2018	118	—	118
December 31, 2019	—	—	—
December 31, 2020	—	—	—

Schedule Of Reserve Value By Category And The Respective Present Values, Before Income Taxes, Discounted At 10% As A Percentage Of Total Proved Reserves

	Year Ended 12/31/2020						Year Ended 12/31/2019						Year Ended 12/31/2018
	Oil		Gas		Total		Oil		Gas		Total		Oil		Gas		Total
Total proved reserves    year-end reserve    report	$	2,897		—	$	2,897	$	8,365		—	$	8,365	$	13,976		—	$	13,976
Proved developed    producing reserves    (PDP)	$	2,598		—	$	2,598	$	7,592		—	$	7,592	$	12,534		—	$	12,534
% of PDP reserves to    total proved reserves		90%		—		90%		91%		—		91%		90%		—		90%
Proved developed non-    producing reserves	$	299		—	$	299	$	773		—	$	773	$	739		—	$	739
% of PDNP reserves to    total proved reserves		10%		—		10%		9%		—		9%		5%		—		5%
Proved undeveloped    reserves (PUD)	$	—		—	$	—	$	—		—	$	—	$	703		—	$	703
% of PUD reserves to    total proved reserves		—		—		—		—		—		—		5%		—		5%

Schedule Of Standardized Measure Of Discounted Futures Net Cash Flows From Proved Oil And Gas Reserves

	Years Ended December 31,
	2020		2019		2018
Future cash inflows	$	18,036	$	40,655	$	65,871
Future production costs and taxes		(12,664)		(24,829)		(35,877)
Future development costs		(538)		(542)		(2,833)
Future income tax expenses		—		—		—
Future net cash flows		4,834		15,284		27,161
Discount at 10% for timing of cash flows		(1,937)		(6,919)		(13,185)
Standardized measure of discounted future net cash flows	$	2,897	$	8,365	$	13,976

Schedule Of Changes In The Standardized Measure Of Discounted Future Net Cash Flows From Proved Oil And Gas Reserves

	Years Ended December 31,
	2020		2019		2018
Balance, beginning of year	$	8,365	$	13,976	$	8,170
Sales, net of production costs and taxes		(210)		(1,646)		(2,611)
Discoveries and extensions, net of costs		—		154		798
Purchase of reserves in place		—		—		143
Sale of reserves in place		—		(26)		—
Net changes in prices and production costs		(2,893)		(3,348)		4,304
Revisions of quantity estimates		(2,353)		(3,058)		2,180
Previously estimated development cost incurred during the year		—		—		210
Changes in future development costs		(314)		1,016		78
Changes in timing and other		(389)		86		(4)
Accretion of discount		691		1,211		708
Net change in income taxes		—		—		—
Balance, end of year	$	2,897	$	8,365	$	13,976

XML

Description Of Business And Significant Accounting Policies (Narrative) (Details)			12 Months Ended
	Feb. 25, 2021	Mar. 21, 2016	Dec. 31, 2020 USD ($) customer	Dec. 31, 2019 USD ($)
Description Of Business And Significant Accounting Policies [Line Items]
Unevaluated properties			$ 0	$ 0
Current cost discount			10.00%
Stock based compensation			$ 14,000	17,000
Deferred tax asset				65,000
Derivatives			$ 0	0
Customers | customer			2
Impairment			$ 920,000	0
Accounts receivable - noncurrent				65,000
Allowance for doubtful accounts			$ 0	$ 0
Reverse stock split		0.1
Customer A [Member] | Revenue [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Customer's percentage of revenue			84.70%	87.70%
Customer B [Member] | Revenue [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Customer's percentage of revenue			11.10%	11.80%
Customer C [Member] | Accounts Receivable [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Customer's percentage of revenue			83.90%	76.90%
Two Customers [Member] | Accounts Receivable [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Customer's percentage of revenue			96.80%	86.00%
Subsequent Event [Member]
Description Of Business And Significant Accounting Policies [Line Items]
Reverse stock split	0.083

XML

Description Of Business And Significant Accounting Policies (Disaggregation Of Revenue) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenue	$ 3,038,000	$ 4,911,000
Crude Oil [Member]
Disaggregation of Revenue [Line Items]
Revenue	3,015,000	4,884,000
Saltwater Disposal Fees [Member]
Disaggregation of Revenue [Line Items]
Revenue	23,000	27,000
Natural Gas Imbalances [Member]
Disaggregation of Revenue [Line Items]
Revenue	$ 0	$ 0

XML

Description Of Business And Significant Accounting Policies (Inventory) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Description Of Business And Significant Accounting Policies [Abstract]
Oil - carried at cost	$ 361	$ 415
Equipment and materials - carried at net realizable value
Total inventory	$ 361	$ 415

XML

Description Of Business And Significant Accounting Policies (Accounts Receivable) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable - current	$ 294	$ 557
Revenue [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable - current	292	415
Tax [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable - current		65
Tax - noncurrent		65
Joint Interest [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable - current	$ 2	$ 77

XML

Description Of Business And Significant Accounting Policies (Reconciliations Of The Numerators And Denominators On Basic And Diluted Earnings Per Share) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Earnings Per Common Share [Abstract]
Net loss	$ (1,754)	$ (813)	$ (554)	$ (527)	$ (167)	$ (182)	$ 9	$ (96)	$ (3,648)	$ (436)
Weighted average shares - basic									889,670	887,612
Dilution effect of share-based compensation, treasury method
Weighted average shares - dilutive									889,670	887,612
Basic	$ (1.92)	$ (0.96)	$ (0.60)	$ (0.60)	$ (0.12)	$ (0.24)	$ 0.01	$ (0.12)	$ (4.10)	$ (0.49)
Dilutive									$ (4.10)	$ (0.49)

XML

Oil And Gas Properties (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Oil And Gas Properties [Abstract]
Depletion expense	$ 569,000	$ 637,000

XML

Oil And Gas Properties (Schedule Of Oil And Gas Properties) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Oil And Gas Properties [Abstract]
Oil and gas properties	$ 6,752	$ 6,751
Ceiling test impairment	(3,855)
Oil and gas properties, net of ceiling test impairment	2,897	6,751
Unevaluated properties
Accumulated depreciation, depletion and amortization	(2,935)	(2,366)
Ceiling test impairment	2,935
Accumulated depreciation, depletion and amortization, net of ceiling test impairment		(2,366)
Oil and gas properties, net	$ 2,897	$ 4,385

XML

Other Property And Equipment (Schedule Of Other Property And Equipment) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Line Items]
Gross Cost	$ 342,000	$ 378,000
Accumulated depreciation	240,000	229,000
Net Book Value	102,000	149,000
Depreciation expense	75,000	79,000
Vehicles [Member]
Property, Plant and Equipment [Line Items]
Gross Cost	259,000	295,000
Accumulated depreciation	157,000	146,000
Net Book Value	102,000	149,000
Other [Member]
Property, Plant and Equipment [Line Items]
Gross Cost	83,000	83,000
Accumulated depreciation	$ 83,000	$ 83,000
Minimum [Member] | Vehicles [Member]
Property, Plant and Equipment [Line Items]
Depreciable Life	2 years	2 years
Minimum [Member] | Other [Member]
Property, Plant and Equipment [Line Items]
Depreciable Life	5 years	5 years
Maximum [Member] | Vehicles [Member]
Property, Plant and Equipment [Line Items]
Depreciable Life	3 years	3 years
Maximum [Member] | Other [Member]
Property, Plant and Equipment [Line Items]
Depreciable Life	7 years	7 years

XML

Long-Term Debt (Narrative) (Details)	3 Months Ended		12 Months Ended
	Dec. 31, 2020 USD ($)	Jun. 30, 2020 USD ($)	Dec. 31, 2020 USD ($)	Feb. 26, 2021 USD ($)	Dec. 31, 2019 USD ($)
Debt Instrument [Line Items]
Other income	$ 166,000
Subsequent Event [Member]
Debt Instrument [Line Items]
Credit facility amount outstanding				$ 0
Prosperity Bank [Member]
Debt Instrument [Line Items]
Interest rate			3.75%
Credit facility current borrowing capacity	3,100,000		$ 3,100,000
Credit facility amount outstanding	0		0		$ 0
Credit limit			1,442,000
Prosperity Bank [Member] | Loans And Letters Of Credit [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 50,000,000		$ 50,000,000
Prosperity Bank [Member] | Paycheck Protection Program Loan [Member]
Debt Instrument [Line Items]
Credit limit		$ 166,000
Maximum [Member] | Prosperity Bank [Member]
Debt Instrument [Line Items]
Funded debt to EBITDA			3.5
Minimum [Member] | Prosperity Bank [Member]
Debt Instrument [Line Items]
Current ratio			1
Interest coverage			3.0

XML

Lease Liabilities (Narrative) (Details)	Dec. 31, 2020 USD ($)
Lessee, Lease, Description [Line Items]
Increased operating lease right of use	$ 63,000
Maximum [Member]
Lessee, Lease, Description [Line Items]
Payment term	36 months
Minimum [Member]
Lessee, Lease, Description [Line Items]
Payment term	18 months
Prosperity Bank [Member]
Lessee, Lease, Description [Line Items]
Borrowing rate	3.75%

XML

Lease Liabilities (Components Of Lease Cost) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lease Cost [Line Items]
Total operating lease cost	$ 63	$ 62
Amortization of right of use assets	75	79
Interest on lease liabilities	5	5
Total finance lease cost	80	84
Production Costs And Taxes [Member]
Lease Cost [Line Items]
Total operating lease cost	13	13
General and Administrative [Member]
Lease Cost [Line Items]
Total operating lease cost	$ 50	$ 49

XML

Lease Liabilities (Supplemental Cash Flow Information Related To Leases) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lease Liabilities [Abstract]
Operating cash flows from operating leases	$ 63	$ 62
Operating cash flows from finance leases	5	5
Finance cash flows from finance leases	41	53
Right of use assets obtained in exchange for lease obligations, Operating leases	$ 63	$ 98

XML

Lease Liabilities (Supplemental Balance Sheet Information Related To Leases) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Lease Liabilities [Abstract]
Right of use asset - operating leases	$ 42	$ 41
Lease liabilities - current	42	41
Total operating lease liabilities	42	41
Other property and equipment, gross	342	295
Accumulated depreciation	(240)	(146)
Other property and equipment, net	102	149
Lease liabilities - current	61	61
Lease liabilities - noncurrent	16	41
Total finance lease liabilities	$ 77	$ 102

XML

Lease Liabilities (Schedule Of Weighted Average Remaining Lease Term And Discount Rate) (Details)	Dec. 31, 2020
Lease Liabilities [Abstract]
Weighted average remaining lease term, Operating Leases	8 months 12 days
Weighted average discount rate, Operating Leases	3.75%
Weighted average remaining lease term, Finance Leases	8 months 12 days
Weighted average discount rate, Finance Leases	5.30%

XML

Lease Liabilities (Maturity Analysis For Operating and Finance Lease Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Lease Liabilities [Abstract]
Operating Leases, 2021	$ 43
Operating Leases, Total lease payments	43
Operating Leases, Less imputed interest	(1)
Total operating lease liabilities	42	$ 41
Finance Leases, 2021	62
Finance Leases, 2022	16
Finance Leases, Total lease payments	78
Finance Leases, Less imputed interest	(1)
Total finance lease liabilities	$ 77	$ 102

XML

Commitments And Contingencies (Narrative) (Details)			12 Months Ended	72 Months Ended
	Feb. 25, 2021	Mar. 21, 2016	Dec. 31, 2020 USD ($) $ / shares $ / bbl shares	Dec. 31, 2020 USD ($) $ / shares
Loss Contingencies [Line Items]
Cost reduction | $			$ 430,000	$ 430,000
Cost reduction paid into common stock | $			$ 117,000
Shares issued for services | shares			8,000
Share price | $ / shares			$ 14.88	$ 14.88
Period of trailing average of WTI			30 days
Reverse stock split		0.1
Subsequent Event [Member]
Loss Contingencies [Line Items]
Reverse stock split	0.083
Minimum [Member] | West Texas Intermediate [Member]
Loss Contingencies [Line Items]
Compensation reduction | $ / bbl			70
Compensation reimbursement | $ / bbl			85

XML

Asset Retirement Obligation (Asset Retirement Obligation Transactions) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation [Abstract]
Balance	$ 1,998	$ 2,179
Accretion expense	125	132
Liabilities incurred		12
Liabilities settled	(25)	(83)
Liabilities sold properties	(50)	(55)
Revisions in estimated liabilities	69	(187)
Balance	$ 2,117	$ 1,998

XML

Stock And Stock Options (Narrative) (Details)					12 Months Ended
	Feb. 25, 2021	Mar. 17, 2017 $ / shares	Mar. 21, 2016	Feb. 01, 2008 shares	Dec. 31, 2020 $ / shares	Oct. 25, 2020 shares	Dec. 31, 2019 $ / shares	Mar. 16, 2017 $ / shares
Stock Options [Line Items]
Number of shares that may be granted | shares						7,000,000
Number of additional shares that may be granted | shares				3,500,000
Stock incentive plan term					10 years
Purchase price floor of fair market value					85.00%
Common stock, par value | $ / shares		$ 0.001			$ 0.001		$ 0.001
Reverse stock split			0.1
Voluntary Resignation [Member]
Stock Options [Line Items]
Stock Incentive Plan exercisable period					3 months
Subsequent Event [Member]
Stock Options [Line Items]
Reverse stock split	0.083
Series A Preferred Stock [Member]
Stock Options [Line Items]
Exercise price | $ / shares								$ 1.10
Rights Plan [Member]
Stock Options [Line Items]
Common stock, Threshold for exercise of rights percentage		4.95%

XML

Stock And Stock Options (Schedule Of Stock Option Activity) (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Stock And Stock Options [Abstract]
Shares, Outstanding beginning of year	781	1,406
Shares, Exercised	(52)
Shares, Expired/cancelled	(625)	(625)
Shares, Outstanding end of year	104	781
Weighted Average Exercise Price, Outstanding beginning of year	$ 26.16	$ 38.16
Weighted Average Exercise Price, Exercised	14.40
Weighted Average Exercise Price, Expired/cancelled	29.16	53.16
Weighted Average Exercise Price, Outstanding end of year	$ 14.40	$ 26.16
Exercisable, end of year, Shares	104	781
Exercisable, end of year, Weighted Average Exercise Price	$ 14.40	$ 26.16

XML

Stock And Stock Options (Schedule Of Stock Options Outstanding And Exercisable) (Details) - $ / shares	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 14.40	$ 26.16	$ 38.16
Options Outstanding	104	781	1,406
Options Exercisable	104
$14.40 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted Average Exercise Price	$ 14.40
Options Outstanding	104
Options Exercisable	104

XML

Income Taxes (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019
Income Taxes [Line Items]
Valuation allowance	$ 11,090,000		$ 10,704,000
Federal net operating loss carryforwards	35,400,000
Deferred tax asset			$ 65,000
Refundable credits	130,000
Refundable credits		$ 130,000
Tax Period Between 2021 And 2037 [Member]
Income Taxes [Line Items]
Federal net operating loss carryforwards	30,100,000
Indefinite Tax Period [Member]
Income Taxes [Line Items]
Federal net operating loss carryforwards	$ 5,300,000
Minimum [Member] | Tax Period Between 2021 And 2037 [Member]
Income Taxes [Line Items]
Federal net operating loss carryforwards expiration between, years	Jan. 01, 2021
Maximum [Member] | Tax Period Between 2021 And 2037 [Member]
Income Taxes [Line Items]
Federal net operating loss carryforwards expiration between, years	Dec. 31, 2037

XML

Income Taxes (Reconciliation Of The Statutory U.S. Federal Income Tax And The Income Tax Provision) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Abstract]
Statutory rate	21.00%	21.00%
Tax (benefit) expense at statutory rate	$ (764)	$ (99)
State income tax (benefit) expense	(148)	321
Permanent difference	184
Return to provision	1
Stock Compensation Tax Deficit - ASU 2016-09	7	4
NOL Expiration	334	557
Other		(40)
Net change in deferred tax asset valuation allowance	386	(771)
Total income tax provision (benefit)		$ (28)

XML

Income Taxes (Schedule Of Deferred Tax Assets And Liabilities) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Income Taxes [Abstract]
Net operating loss carryforwards	$ 9,596	$ 9,119
Oil and gas properties	922	1,054
Property, Plant and Equipment	1
Property, Plant and Equipment		(5)
Asset retirement obligation	542	500
Tax credits		65
Miscellaneous	29	36
Valuation allowance	(11,090)	(10,704)
Net deferred tax asset		$ 65

XML

Quarterly Data And Share Information (Schedule Of Quarterly Data) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019
Quarterly Data And Share Information [Abstract]
Revenues	$ 747	$ 765	$ 563	$ 963	$ 1,135	$ 1,215	$ 1,390	$ 1,171	$ 3,038	$ 4,911
Net income (loss)	$ (1,754)	$ (813)	$ (554)	$ (527)	$ (167)	$ (182)	$ 9	$ (96)	$ (3,648)	$ (436)
Income (loss) per common share	$ (1.92)	$ (0.96)	$ (0.60)	$ (0.60)	$ (0.12)	$ (0.24)	$ 0.01	$ (0.12)	$ (4.10)	$ (0.49)

XML

Supplemental Oil And Gas Information (Narrative) (Details)	12 Months Ended
	Dec. 31, 2020 USD ($) item $ / bbl	Dec. 31, 2019 item $ / bbl	Dec. 31, 2018 item $ / bbl
Oil And Gas, Average Sale Price And Production Cost Per Unit [Line Items]
Proved undeveloped reserve locations | item	0	0	7
Depreciation, depletion, or any indirect cost | $	$ 0
Barrel Of Oil [Member]
Oil And Gas, Average Sale Price And Production Cost Per Unit [Line Items]
Price | $ / bbl	34.87	50.65	60.21

XML

Supplemental Oil And Gas Information (Schedule Of Capitalized Costs Related To Oil And Gas Producing Activities) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Supplemental Oil And Gas Information [Abstract]
Oil and gas properties	$ 6,752	$ 6,751
Ceiling test impairment	(3,855)
Oil and gas properties, net of ceiling test impairment	2,897	6,751
Unevaluated properties
Accumulated depreciation, depletion and amortization	(2,935)	(2,366)
Ceiling test impairment	2,935
Accumulated depreciation, depletion and amortization, net of ceiling test impairment		(2,366)
Oil and gas properties, net	$ 2,897	$ 4,385

XML

Supplemental Oil And Gas Information (Schedule Of Oil And Gas Property Acquisition, Exploration And Development) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Supplemental Oil And Gas Information [Abstract]
Property acquisitions proved
Property acquisitions unproved	6	14
Exploration cost	1	491
Development cost	14	7
Total	$ 21	$ 512

XML

Supplemental Oil And Gas Information (Schedule Of Results Of Operations From Oil And Gas Producing Activities) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Supplemental Oil And Gas Information [Abstract]
Revenues	$ 3,038	$ 4,911
Production costs and taxes	(3,104)	(3,398)
Depletion	(569)	(637)
Income (loss) from oil and gas producing activities	$ (635)	$ 876

XML

Supplemental Oil And Gas Information (Schedule Of Net Proved Oil And Gas Reserves And The Changes In Net Proved Oil And Gas Reserves) (Details)	12 Months Ended
	Dec. 31, 2020 MBoe MMcf MBbls	Dec. 31, 2019 MBoe MMcf MBbls	Dec. 31, 2018 MBoe MMcf MBbls
Reserve Quantities [Line Items]
Proved reserves	803	1,094
Revisions of previous estimates	(200)	(203)
Improved recovery
Purchase of reserves in place
Extensions and discoveries		8
Production	(86)	(94)
Sales of reserves in place		(2)
Proved reserves	517	803	1,094
Proved developed reserves (equivalent) | MBoe	517	803	976
Proved undeveloped reserves (equivalent) | MBoe			118
Oil [Member]
Reserve Quantities [Line Items]
Proved reserves	803	1,094
Revisions of previous estimates	(200)	(203)
Improved recovery
Purchase of reserves in place
Extensions and discoveries		8
Production	(86)	(94)
Sales of reserves in place		(2)
Proved reserves	517	803	1,094
Proved developed reserves (volume)	517	803	976
Proved undeveloped reserves (volume)			118
Gas [Member]
Reserve Quantities [Line Items]
Proved reserves | MMcf
Revisions of previous estimates | MMcf
Improved recovery | MMcf
Purchase of reserves in place | MMcf
Extensions and discoveries | MMcf
Production | MMcf
Sales of reserves in place | MMcf
Proved reserves | MMcf
Proved developed reserves (volume) | MMcf
Proved undeveloped reserves (volume) | MMcf

XML

Supplemental Oil And Gas Information (Schedule Of Reserve Value By Category And The Respective Present Values, Before Income Taxes, Discounted At 10% As A Percentage Of Total Proved Reserves) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reserve Quantities [Line Items]
Total proved reserves year-end reserve report	$ 2,897	$ 8,365	$ 13,976
Proved developed producing reserves (PDP)	$ 2,598	$ 7,592	$ 12,534
% of PDP reserves to total proved reserves	90.00%	91.00%	90.00%
Proved developed non-producing reserves	$ 299	$ 773	$ 739
% of PDNP reserves to total proved reserves	10.00%	9.00%	5.00%
Proved undeveloped reserves (PUD)			$ 703
% of PUD reserves to total proved reserves			5.00%
Oil [Member]
Reserve Quantities [Line Items]
Total proved reserves year-end reserve report	$ 2,897	$ 8,365	$ 13,976
Proved developed producing reserves (PDP)	$ 2,598	$ 7,592	$ 12,534
% of PDP reserves to total proved reserves	90.00%	91.00%	90.00%
Proved developed non-producing reserves	$ 299	$ 773	$ 739
% of PDNP reserves to total proved reserves	10.00%	9.00%	5.00%
Proved undeveloped reserves (PUD)			$ 703
% of PUD reserves to total proved reserves			5.00%
Gas [Member]
Reserve Quantities [Line Items]
Total proved reserves year-end reserve report
Proved developed producing reserves (PDP)
% of PDP reserves to total proved reserves
Proved developed non-producing reserves
% of PDNP reserves to total proved reserves
Proved undeveloped reserves (PUD)
% of PUD reserves to total proved reserves

XML

Supplemental Oil And Gas Information (Schedule Of Standardized Measure Of Discounted Futures Net Cash Flows From Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Oil And Gas Information [Abstract]
Future cash inflows	$ 18,036	$ 40,655	$ 65,871
Future production costs and taxes	(12,664)	(24,829)	(35,877)
Future development costs	(538)	(542)	(2,833)
Future income tax expenses
Future net cash flows	4,834	15,284	27,161
Discount at 10% for timing of cash flows	(1,937)	(6,919)	(13,185)
Standardized measure of discounted future net cash flows	$ 2,897	$ 8,365	$ 13,976	$ 8,170

XML

Supplemental Oil And Gas Information (Schedule Of Changes In The Standardized Measure Of Discounted Future Net Cash Flows From Proved Oil And Gas Reserves) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Oil And Gas Information [Abstract]
Balance, beginning of year	$ 8,365	$ 13,976	$ 8,170
Sales, net of production costs and taxes	(210)	(1,646)	(2,611)
Discoveries and extensions, net of costs		154	798
Purchase of reserves in place			143
Sale of reserves in place		(26)
Net changes in prices and production costs	(2,893)	(3,348)	4,304
Revisions of quantity estimates	(2,353)	(3,058)	2,180
Previously estimated development cost incurred during the year			210
Changes in future development costs	(314)	1,016	78
Changes in timing and other	(389)	86	(4)
Accretion of discount	691	1,211	708
Net change in income taxes
Balance, end of year	$ 2,897	$ 8,365	$ 13,976

XML

Subsequent Events (Details) $ in Millions	Mar. 01, 2021 USD ($)
Kansas | Subsequent Event [Member]
Subsequent Event [Line Items]
Discontinued Operation, Sale Price	$ 3.5