# Riley Exploration Permian, Inc.: Form 10-K for the period ended Dec 31, 2019

- Company: [Riley Exploration Permian, Inc.](/companies/repx.md) (CIK 1001614)
- Form: 10-K
- Filed: 2020-03-30
- Accepted by EDGAR: Mar 30, 2020, 16:41 ET
- Period: 2019-12-31
- Accession: 0001140361-20-007405
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/1001614/000114036120007405/form10k.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/1001614/000114036120007405/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2019-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Revenue | 3 months, 2019-10-01 to 2019-12-31 | $1.1m | us-gaap:Revenues |
| Revenue | 12 months, 2019-01-01 to 2019-12-31 | $4.9m | us-gaap:RevenueFromContractWithCustomerExcludingAssessedTax |
| Operating income | 12 months, 2019-01-01 to 2019-12-31 | −$505.0k | us-gaap:OperatingIncomeLoss |
| Interest expense | 12 months, 2019-01-01 to 2019-12-31 | $10.0k | us-gaap:InterestExpense |
| Income tax | 12 months, 2019-01-01 to 2019-12-31 | −$28.0k | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2019-01-01 to 2019-12-31 | −$436.0k | us-gaap:NetIncomeLoss |
| Basic EPS | 3 months, 2019-10-01 to 2019-12-31 | −$0.01 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2019-01-01 to 2019-12-31 | 10,651,342 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Operating cash flow | 12 months, 2019-01-01 to 2019-12-31 | $226.0k | us-gaap:NetCashProvidedByUsedInOperatingActivities |
| Cash and equivalents | at 2019-12-31 | $3.1m | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2019-12-31 | $4.3m | us-gaap:AssetsCurrent |
| Total assets | at 2019-12-31 | $8.9m | us-gaap:Assets |
| Current liabilities | at 2019-12-31 | $610.0k | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2019-12-31 | $2.6m | us-gaap:Liabilities |
| Shareholders' equity | at 2019-12-31 | $6.3m | us-gaap:StockholdersEquity |

## Business

As filed, 20,513 characters.

### 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. The Company is now a Delaware corporation.

### OVERVIEW

The Company is in the business of exploration for and production of oil and natural gas. The Company’s only areas of operations are in Kansas. However, in addition to Kansas, the Company also looks at potential opportunities in other states.

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 a 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.

### General

### 1\. The Kansas Properties

The Company’s operated properties in Kansas are located in central Kansas and as of December 31, 2019 included 174 producing oil wells, 13 shut-in wells, and 37 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.

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. 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 9.3 MBbl from 120.2 MBbl in 2018 to 110.9 MBbl in 2019. 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, partially offset by higher sales volumes attributed to the BSU #1-30 well that was completed in October 2018. The capital projects undertaken by the Company during 2019 were primarily funded by cash on hand and operating cash flows.

### 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. The terms of the Program also provided that Hoactzin would receive all the working interest in the producing wells, and would pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses as a management fee. The fee paid to the Company increased from 25% to 85% in February 2014.

In 2018, the wells from the Program produced total gross production of 6.8 MBbl of which the revenues from 5.8 MBbl were net to the Company. During the 4th 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.

### 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.

### 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.

Electricity generated at the Company’s MMC site in Tennessee was sold to Holston Electric Cooperative and TVA.

### Drilling Equipment

The Company does not currently 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. Electricity generated at the Company’s Methane Facility was distributed into the electric grid.

### 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. Management does not believe that the Company’s competitive position in the oil and gas industry will be significant as the Company currently exists.

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.

### 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.

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.

### Number of Total Employees and Number of Full-Time Employees

At December 31, 2019, the Company had 12 full time employees and no part-time employees. These employees are located in Colorado, Kansas, and Texas.

### 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.tengasco.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.

## Risk factors

As filed, 36,042 characters.

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, 2019, the Company had no outstanding principal amount of indebtedness under its credit facility with Prosperity Bank. Although the Company had no bank indebtedness, should it 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 existing 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.

**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.**

Because the availability of borrowings by the Company under the terms of the Company’s amended and restated credit facility with Prosperity Bank 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 its Credit Facility May be Reduced by the Lender.**

The borrowing base under the Company’s revolving credit facility 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.**

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 the outstanding borrowings sooner than currently required by the agreement.

**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, 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, and 2016, impairments of its pipeline assets during 2010 and 2012, and an impairment of its methane facility in 2014. As of December 31, 2019, the Company has an accumulated deficit of $52.0 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, and $0.5 million in 2019. In the event the Company experiences losses in the future, those losses may curtail the Company’s development and operating activities.

**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.

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. 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.

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

At December 31, 2019, 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. 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. 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, 2019, federal net operating loss carryforwards amounted to approximately $33.8 million, of which $31.5 million expires between 2020 and 2037 which can offset 100% of taxable income and $2.3 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was $65,000 at December 31, 2019 and $130,000 at 2018. In 2018, the Company released a portion of the allowance related to its MTC as a result of the 2017 Tax Act. 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 a full allowance against the deferred tax asset net of the AMT credit at December 31, 2018 primarily due to cumulative losses incurred during the 3 years ended December 31, 2018. The total valuation allowance December 31, 2019 was $10.7 million, and $11.5 million at December 31, 2018.

**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.

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.

### 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.

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 is a small entity with limited financial resources and 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.

**The Company’s Chairman of the Board Beneficially Controls a Substantial Amount of the Company’s Common Stock and Has Significant Influence over the Company’s Business.**

Peter E. Salas, the Chairman of the Company’s Board of Directors, is the sole shareholder and controlling person of Dolphin Mgmt. Services, Inc. the general partner of Dolphin Offshore Partners, L.P. (“Dolphin”), which is the Company’s largest shareholder. At March 23, 2020, Mr. Salas individually and through Dolphin controls 5,296,241 shares of the Company’s common stock and had options granting him the right to acquire an additional 3,125 shares of common stock. His ownership and voting control of approximately 49.7% of the Company’s common stock gives him significant influence on the outcome of corporate transactions or other matters submitted to the Board of Directors or shareholders for approval, including mergers, consolidations, and the sale of all or substantially all of the Company’s assets.

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

At March 23, 2020, the Company had 10,666,211 shares of common stock outstanding of which 5,481,580 shares were held by officers, directors, and affiliates. In addition, options to purchase 9,375 shares of unissued common stock were granted under the Tengasco, Inc. Stock Incentive Plan all of which were vested at March 23, 2020.

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 10.7 million shares have been issued. The potential issuance of the approximately 89.3 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.

**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.

## Properties

As filed, 10,886 characters.

### Property Location, Facilities, Size and Nature of Ownership.

The Company leases its principal executive offices, consisting of approximately 1,978 square feet located at 8000 E. Maplewood Ave., Suite 130, Greenwood Village, Colorado at a current rental of $4,318 per month, expiring in August 2020. The Company also leases 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. The Company also carried property insurance on its methane facility which has been discontinued as a result of the sale of this facility in January 2018. As of December 31, 2019, the Company does not have an interest in producing or non-producing oil and gas properties in any state other than Kansas.

### Kansas Properties

The Kansas Properties as of December 31, 2019 contained 16,552 gross acres (11,816 net acres) in central Kansas. Of these acres, 14,320 gross acres (11,361 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 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. By using 3-D seismic evaluation on the Company’s existing locations, the Company has historically added proven direct offset locations.

### Reserve and Production Summary

The following tables indicate the county breakdown of 2019 production and reserve values as of December 31, 2019.

### Production by County

| Area | Gross Production MBOE | Average Net Revenue Interest | Percentage of Total Oil Production |
| --- | ---: | ---: | ---: |
| Rooks County, KS | 76.7 | 0.830134 | 69.1% |
| Trego County, KS | 12.8 | 0.806984 | 11.5% |
| Ellis County, KS | 5.8 | 0.800628 | 5.2% |
| Barton County, KS | 5.2 | 0.814272 | 4.7% |
| Russell County, KS | 2.9 | 0.827102 | 2.7% |
| Graham County, KS | 2.9 | 0.873081 | 2.6% |
| Rush County, KS | 2.1 | 0.872476 | 1.9% |
| Osborne County, KS | 1.2 | 0.597838 | 1.1% |
| Pawnee County, KS | 1.2 | 0.833196 | 1.1% |
| Stafford County, KS | 0.1 | 0.716151 | 0.1% |
| **Total** | **110.9** |  | **100.0%** |

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

| Area | Proved Developed | Proved Undeveloped | Proved Reserves | % of Total |
| --- | ---: | ---: | ---: | ---: |
| Rooks County, KS | $5,885 | $— | $5,885 | 70.3% |
| Trego County, KS | 1,029 | — | 1,029 | 12.3% |
| Barton County, KS | 525 | — | 525 | 6.3% |
| Ellis County, KS | 314 | — | 314 | 3.7% |
| Graham County, KS | 248 | — | 248 | 3.0% |
| Rush County, KS | 232 | — | 232 | 2.8% |
| Russell County, KS | 68 | — | 68 | 0.8% |
| Pawnee County, KS | 64 | — | 64 | 0.8% |
| Osborne County, KS | — | — | — | —% |
| Stafford County, KS | — | — | — | —% |
| Ness County, KS | — | — | — | —% |
| Logan County, KS | — | — | — | —% |
| **Total** | **$8,365** | **$—** | **$8,365** | **100.0%** |

18

### Reserve Analyses

The Company’s estimated total net proved reserves of oil and natural gas as of December 31, 2019 and 2018, 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.

### 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 |

### Total Proved Reserves as of December 31, 2018

|  | Producing | Non-producing | Undeveloped | Total |
| --- | ---: | ---: | ---: | ---: |
| Oil (MBbl) | 948 | 28 | 118 | 1,094 |
| Future net cash flows before income taxes discounted at 10% (in thousands) | $12,534 | $739 | $703 | $13,976 |

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, 2019 reserve valuation was $50.65 per Bbl compared to $60.21 per Bbl used in our December 31, 2018 reserve valuation. The primary factor causing the decrease in proved developed reserve volumes and removal of all undeveloped reserve volumes from December 31, 2018 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, 2019. 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*

| Years Ended December 31, | Gross Production Oil (MBbl) | Gas (MMcf) | Net Production Oil (MBbl) | Gas (MMcf) | Cost of Net Production (Per BOE) | Average Sales Price Oil (Bbl) | Gas (Per Mcf) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| 2019 | 111 | — | 91 | — | $34.55 | $52.12 | — |
| 2018 | 120 | — | 98 | — | $32.52 | $59.48 | — |

### 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.

### Gross and Net Wells

The following tables set forth the fiscal years ending December 31, 2019 and 2018 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.

| Kansas | For Years Ending December 31, 2019 Gross | Net | 2018 Gross | Net |
| --- | ---: | ---: | ---: | ---: |
| Productive Wells | 2 | 1.1 | 1 | 0.9 |
| Dry Holes | 1 | 0.9 | 4 | 1.5 |

### Productive Wells

As of December 31, 2019, the Company held a working interest in 192 gross wells, including interest in 5 properties operated by others, and 186 net wells in Kansas. Productive wells are either producing wells or wells capable of commercial production although currently shut-in. One or more completions in the same bore hole are counted as one well. 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, 2019, 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 Gross Acres | Net Acres | Undeveloped Gross Acres | Net Acres | Total Gross Acres | Net Acres |
| --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Kansas | 14,320 | 11,361 | 2,232 | 455 | 16,552 | 11,816 |

20

The following table identifies the number of gross and net undeveloped acres as of December 31, 2019 that will expire, by year, unless production is established before lease expiration or unless the lease is renewed.

|  | 2021 | Total |
| --- | ---: | ---: |
| Gross Acres | 2,232 | 2,232 |
| Net Acres | 455 | 455 |

## Legal proceedings

As filed, 546 characters.

The Company is not a party to any pending material legal proceeding. To the knowledge of management, no federal, state, or local governmental agency is presently contemplating any proceeding against the Company which would have a result materially adverse to the Company. To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or 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.

## Management's discussion and analysis

As filed, 17,827 characters.

### Results of Operations

The Company reported a net loss income from continuing operations of $(436,000) or $(0.04) per share in 2019 compared to net income of $442,000 or $0.04 per share in 2018.

The Company realized revenues of approximately $4.9 million in 2019 compared to $5.9 million in 2018. During 2019, revenues decreased approximately $960,000 of which $689,000 of this decrease related to a $7.36 per barrel decrease in the average oil price received from $59.48 per barrel received in 2018 to $52.12 per barrel received in 2019. Revenue also decreased approximately $266,000 related to a 4.5 MBbl decrease in oil sales volumes from 98.2 MBbl in 2018 to 93.7 MBbl in 2019. 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 as well as natural declines on other properties, partially offset by sales volumes from the BSU #1-30 well that was completed in Q4 2018.

The Company’s production costs and taxes were approximately $3.4 million in 2019 compared to $3.6 million in 2018. The $193,000 decrease in 2019 was primarily due to a change in the oil inventory adjustment as well as lower utility costs.

Depreciation, depletion, and amortization was approximately $716,000 in 2019 compared to $795,000 in 2018. The $79,000 decrease in 2019 was due to a $52,000 decrease related to a decrease in the oil and gas depletion rate primarily as a result of lower future development costs in connection with the Company’s removal of its undeveloped reserves at December 31, 2019, and a $33,000 decrease related to lower sales volumes.

The Company’s general and administrative cost was approximately $1.3 million in 2019 compared to $1.25 million in 2018. The $57,000 increase in 2019 was primarily due to a $50,000 payment to Roth Capital related to the process initiated by the company to explore potential transactions or combinations.

The Company performed its assessment for impairment during 2019 and 2018. No impairments of oil and gas properties or other assets resulted from the Company’s assessment.

Other income (expense) was $6,000 in 2019 compared to $157,000 in 2018. The amount recorded in 2018 was primarily due to write off of Accounts payable – other. This write off occurred as the Company determined that the outstanding balance was not recoverable against the Company by operation of applicable statutes of limitation or prescription.

During 2019 and 2018, the Company did not have any open derivative positions.

### Liquidity and Capital Resources

At December 31, 2019, the Company had a revolving credit facility with Prosperity Bank. This 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 are available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $50 million or the Company’s borrowing base in effect from time to time. As of December 31, 2019, the Company’s borrowing base was $4 million, subject to a credit limit based on current covenants of approximately $1.97 million. The credit facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties. The credit facility includes certain covenants with which the Company is required to comply. At December 31, 2019, 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, 2019, the interest rate on this credit facility was 5.25%. The Company was in compliance with all covenants as of December 31, 2019.

On November 20, 2019, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s most recent review of the Company’s currently owned producing properties was amended to decrease the credit limit based on current covenants to approximately $1.97 million. The borrowing base remains subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum. This rate was 5.25% at the date of the amendment. The maximum line of credit of the Company under the Prosperity Bank credit facility remained $50 million.

The Company had zero borrowings under the facility at December 31, 2019 and December 31, 2018. The next borrowing base review will take place in April 2020.

Net cash provided by operating activities by continuing operations was $226,000 in 2019 and $1.3 million in 2018. Cash flow used in working capital during 2019 was $163,000 and $79,000 during 2018. The change in cash provided by operating activities during 2019 was primarily related to decreased revenues as a result of lower oil prices, and decreased revenues as a result of lower sales volumes.

Net cash used in investing activities was $233,000 compared to $1.0 million in 2018. The $790,000 decrease in cash used in investing activities during 2019 was due primarily to drilling and polymer costs incurred during 2018, and proceeds from the sale of equipment inventory in 2019.

Net cash used by in financing activities was $53,000 in 2019 compared to $42,000 in 2018. The change in net cash used in financing activities was due to higher lease costs associated with the Company’s field vehicles.

### 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

Effective January 1, 2018, the Company adopted ASU 2014-09 *Revenue from Contracts with Customers.* 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.

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):

| Revenue (in thousands): | Year Ended December 31, 2019 | Year Ended December 31,2018 |
| --- | ---: | ---: |
| Crude oil | $4,884 | $5,840 |
| Salt water disposal fees | 27 | 31 |
| Total | $4,911 | $5,871 |

There were no natural gas imbalances at December 31, 2019 or December 31, 2018.

### 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, 2019 and 2018. 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, 2019 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.

### 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

In February 2016, the FASB issued ASU 2016-02 *Leases (Topic 842).* This guidance was issued to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. This guidance is effective for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. Early application of the amendments was permitted for all entities. The Company has identified each of its leases and determined the impact of this new guidance on each of the identified leases. The Company implemented ASU 2016-02 *Leases (Topic 842)* as of January 1, 2019 using the modified retrospective approach. As a result of this implementation, the Company recorded right-of-use assets and liabilities associated with operating leases of approximately $98,000. There was no transition adjustment related to finance leases.

The Company elected the package of practical expedients within ASU 2016-02 *Leases (Topic 842)* that allows an entity to not reassess, prior to the effective date, (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification of any expired or existing leases, or (iii) initial direct costs for any existing leases. Additionally, the Company elected the practical expedient to not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The Company also made an account policy election not to apply the lease recognition requirements to leases with an initial term of 12 months or less.

### Contractual Obligations

The following table summarizes the Company’s contractual obligations due by period as of December 31, 2019 (in thousands):

| Contractual Obligations | Total | 2020 | 2021 | 2022 |
| --- | ---: | ---: | ---: | ---: |
| Long-Term Debt Obligations1 | $— | $— | $— | $— |
| Operating Lease Obligations | 42 | 42 | — | — |
| Finance Lease Obligations | 104 | 65 | 39 | — |
| Estimated Interest on Obligations | 7 | 6 | 1 | — |
| Total | $153 | $113 | $40 | $— |

(1) The credit facility with Prosperity Bank had a zero balance at December 31, 2019.

## Market risk

As filed, 3,546 characters.

### 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 2019 ranged from a low of $46.39 per barrel to a high of $58.60 per barrel. During the first quarter of 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, combined with an oil price war between Saudi Arabia and Russia which is further depressing 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 2019 or 2018 but may participate in derivative activities in the future.

### Interest Rate Risk

At December 31, 2019, the Company had finance leases outstanding of approximately $102,000, and no amounts owed on its credit facility with Prosperity Bank. As of December 31, 2019, 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, 2019 was 5.25%. The Company’s finance leases of $102,000 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, 2019 or 2018.

### 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.

## Controls and procedures

As filed, 5,218 characters.

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. Michael J. Rugen, the Company’s Chief Financial Officer is currently also serving as Company’s Chief Executive Officer on an interim basis. Mr. Rugen is acting in both capacities and has executed the accompanying certifications as to both offices.

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.

### 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, 2019. 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, 2019.

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, 2019, 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.

Filed Mar 30, 2020.
Source: SEC EDGAR, the filing index for accession 0001140361-20-007405. Last ingested by Listed: Nov 4, 2026, 18:14 ET. No prices; not investment advice.