Riley Exploration Permian, Inc. - Annual Report: 2018 (Form 10-K)
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
REPORT ON FORM 10-K
(Mark one)
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Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 2018 or
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Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from __________ to __________.
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Commission File No. 1-15555
TENGASCO, INC.
(name of registrant as specified in its charter)
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Delaware
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87-0267438
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(state or other jurisdiction of
Incorporation or organization)
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(I.R.S. Employer
Identification No.)
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8000 E. Maplewood Ave., Suite 130,
Greenwood Village, CO
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80111
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(Address of Principal Executive Offices)
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(Zip Code)
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Registrant’s telephone number, including area code: (720) 420-4460.
Securities registered pursuant to Section 12(b) of the Act: None.
Securities registered pursuant to Section 12(g) of the Act: Common Stock,
$.001 par value per share.
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes ☐ No ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicated by check mark whether the registrant (1) filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by checkmark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files) Yes ☒ No ☐
Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation S-K (§229.405 of this Chapter) is not contained herein, and will
not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an
emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
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Large Accelerated Filer ☐
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Accelerated Filer ☐
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Non-accelerated Filer ☐
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Smaller Reporting Company ☒
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(Do not check if a Smaller Reporting Company)
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Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new
or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐
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Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was
last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $3.9 million (June 29, 2018 closing price $0.75).
The number of shares outstanding of the registrant’s $.001 par value common stock as of the close of business on March 25, 2019 was 10,644,252.
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PART I
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Page
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Item 1.
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6
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Item 1A.
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11
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Item 1B.
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17
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Item 2.
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17
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Item 3.
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21
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Item 4.
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21
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PART II
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Item 5.
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22
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Item 6.
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22
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Item 7.
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23
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Item 7A.
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27
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Item 8.
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28
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Item 9.
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28
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Item 9A.
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28
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Item 9B.
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29
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PART III
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Item 10.
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29
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Item 11.
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33
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Item 12.
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36
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Item 13.
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37
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Item 14.
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40
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PART IV
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Item 15.
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41
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43
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FORWARD LOOKING STATEMENTS
The information contained in this Report, in certain instances, includes forward-looking statements within the meaning of
applicable securities laws. Forward-looking statements include statements regarding the Company’s “expectations,” “anticipations,” “intentions,” “beliefs,” or “strategies” or any similar word or phrase regarding the future. Forward-looking
statements also include statements regarding revenue margins, expenses, and earnings analysis for 2018 and thereafter; oil and gas prices; exploration activities; development expenditures; costs of regulatory compliance; environmental matters;
technological developments; future products or product development; the Company’s products and distribution development strategies; potential acquisitions or strategic alliances; liquidity and anticipated cash needs and availability; prospects for
success of capital raising activities; prospects or the market for or price of the Company’s common stock; and control of the Company. All forward-looking statements are based on information available to the Company as of the date hereof, and the
Company assumes no obligation to update any such forward-looking statement. The Company’s actual results could differ materially from the forward-looking statements. Among the factors that could cause results to differ materially are the factors
discussed in “Risk Factors” below in Item 1A of this Report.
Projecting the effects of commodity prices, which in past years have been extremely volatile, 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.
GLOSSARY OF OIL AND GAS TERMS
The following are abbreviations and definitions of certain terms commonly used in the oil and gas industry and this document:
Bbl. One stock tank barrel, or 42 U.S. gallons
liquid volume, used in reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet of gas.
BOE. One stock tank barrel equivalent of oil,
calculated by converting gas volumes to equivalent oil barrels at a ratio of 6 thousand cubic feet of gas to 1 barrel of oil.
BOPD. Barrels of oil per day.
Btu. British thermal unit. One British thermal
unit is the amount of heat required to raise the temperature of one pound of water by one degree Fahrenheit.
Developed oil and gas reserves. Developed oil
and gas reserves are reserves of any category that can be expected to be recovered: (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a
new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
Development project. A development project is
the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field or the integrated development of a group of
several fields and associated facilities with a common ownership may constitute a development project.
Development well. A well drilled within the
proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil
or gas from an established spot market price to reflect differences in the quality and/or location of oil or gas.
Economically producible. The term economically
producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point
of oil and gas producing activities. The terminal point is generally regarded as the outlet valve on the lease or field storage tank.
Estimated ultimate recovery (EUR). Estimated
ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date,
Exploratory well. A well drilled to find a new
field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test
well.
Farmout. An assignment of an interest in a
drilling location and related acreage conditional upon the drilling of a well on that location.
Gas. Natural gas.
MBbl. One thousand barrels of oil or other
liquid hydrocarbons.
MBOE. One thousand BOE.
Mcf. One thousand cubic feet of gas.
Mcfd. One thousand cubic feet of gas per day
MMcfe. One million cubic feet of gas equivalent.
MMBOE. One million BOE.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of gas.
NYMEX. New York Mercantile Exchange.
Oil. Crude oil, condensate, and natural gas
liquids.
Operator. The individual or company responsible
for the exploration and/or production of an oil or gas well or lease.
Play. A geographic area with hydrocarbon
potential.
Polymer. A polymer gel treatment of a well that
produces from a water-drive reservoir is intended to reduce excessive water production and increase oil or gas production. Candidate wells are typically produced from naturally fractured carbonate reservoirs such as dolomites and limestone in mature
fields. Successful treatments are also run in certain types of sandstone reservoirs. Other practical applications of polymer gels include the treatment of waterflood injection wells to correct channeling or change the injection profile, to improve
the ability of the injected fluids to sweep the producing wells in the field, making the waterflood more efficient and allowing the operator to recover more oil in a shorter period of time.
Proved oil and gas reserves. Proved oil and gas
reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing
economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or
probabilistic methods are used for estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.
The area of the reservoir considered as proved includes all of the following: (i) the area identified by drilling and limited by fluid contacts, if any; and (ii) adjacent undrilled portions of the
reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil and gas on the basis of available geoscience and engineering data.
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless
geoscience, engineering, or performance data and reliable technology establish a lower contact with reasonable certainty.
Where direct observation from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included
in the proved classification when: (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous
reservoir or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and
entities, including governmental entities.
Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average
price during the twelve-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by
contractual arrangements, excluding escalations based upon future conditions.
Proved reserve additions. The sum of additions
to proved reserves from extensions, discoveries, improved recovery, acquisitions, and revisions of previous estimates.
Reserves. Reserves are estimated remaining
quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation
that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market and all permits and financing required to implement the project. Reserves should not
be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known
accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).
Reserve additions. Changes in proved reserves
due to revisions of previous estimates, extensions, discoveries, improved recovery, and other additions and purchases of reserves in-place.
Reserve life. A measure of the productive life
of an oil or gas property or a group of properties, expressed in years.
Royalty interest. An interest in an oil and gas
lease that gives the owner of the interest the right to receive a portion of the production from the leased acreage (or of the proceeds of the sale thereof), but generally does not require the owner to pay any portion of the costs of drilling or
operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of the
leasehold in connection with a transfer to a subsequent owner.
Standardized measure. The present value,
discounted at 10% per year, of estimated future net revenues from the production of proved reserves, computed by applying sales prices used in estimating proved oil and gas reserves to the year-end quantities of those reserves in effect as of the
dates of such estimates and held constant throughout the productive life of the reserves and deducting the estimated future costs to be incurred in developing, producing, and abandoning the proved reserves (computed based on year-end costs and
assuming continuation of existing economic conditions). Future income taxes are calculated by applying the appropriate year-end statutory federal and state income tax rates with consideration of future tax rates already legislated, to pre-tax future
net cash flows, net of the tax basis of the properties involved and utilization of available tax carryforwards related to proved oil and gas reserves.
SWD. Salt water disposal well.
Undeveloped oil and gas reserves. Undeveloped
oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be
limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater
distances.
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be
drilled within five years, unless the specific circumstances justify a longer time. Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery
technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
Waterflood. A method of secondary recovery in
which water is injected into the reservoir formation to displace residual oil. The water from injection wells physically sweeps the displaced oil to adjacent production wells.
Working interest. An interest in an oil and gas
lease that gives the owner of the interest the right to drill for and produce oil and gas from the leased acreage and requires the owner to pay a share of the costs of drilling and production operations.
References herein to the “Company”, “we”, “us” and “our” mean Tengasco, Inc.
PART I
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 primary area of exploration and
production is in Kansas.
The Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owned and operated a pipeline which it constructed to
transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee. The Company sold all its pipeline assets on August 16, 2013.
The Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) operated 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, 2018 included 174 producing oil wells, 20
shut-in wells, and 38 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 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 2018, the Company participated in drilling two operated wells, one of which was completed as a producing well, and three
non-operated wells, none of which were completed as producing wells. All of the Company’s current reserve value, production, oil and gas revenue, and future development objectives result from the Company’s ongoing interest in Kansas. 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 1.5 MBbl from 121.7 MBbl in 2017 to 120.2 MBbl in 2018. This decrease
was primarily the result of natural declines during 2018, partially offset by polymer work performed in the second and third quarters of 2018 and completion of a drilling well in October 2018. The capital projects undertaken by the Company in 2018
were primarily funded by cash flow.
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. Oil, Gas, and Pipeline Assets
In July 1995, the Company acquired the Swan Creek leases and began development of the field. In 2001, the Company completed construction
of a 65 mile pipeline from the Swan Creek Field to several meter stations in Kingsport, Tennessee. On August 16, 2013, the Company closed a sale to Swan Creek Partners LLC of all of the Company’s oil and gas leases and producing assets in Tennessee
as well as all the Company’s pipeline assets for $1.5 million.
B. 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 and Costs and Effects of Compliance with Environmental Laws”
hereinafter in this section.
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 Refining and Marketing, LLC (“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 insure 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 avoiding 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, 2018, the Company had 12 full time employees and no part-time employees. These employees are located in Colorado, Kansas,
and Texas. At January 26, 2018, the Company reduced its number of full time employees from 14 to 13 and no longer has any employees in Tennessee. This employee reduction was a result of the Company selling its Manufactured Methane assets located at
the Carter Valley landfill in Tennessee. During 2018, the company reduced its Kansas employees by one, resulting in the 12 full time employees at December 31, 2018.
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.
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, 2018, 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, 2018, the Company has an accumulated deficit of $51.5 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, and $0.6 million in 2017. 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 since the quarter ended September 30, 2014, during 2015 the Company experienced ceiling test
failures 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 prices continue at depressed levels 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, 2018, 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, 2018, federal net operating loss carryforwards amounted to approximately $35.6 million, of which $34.6 million expires
between 2019 and 2037 which can offset 100% of taxable income and $1 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was $130,000 at December 31, 2018 and $242,000
at 2017. 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, 2018 primarily due to cumulative losses
incurred during the 3 years ended December 31, 2018. The Company recorded a full allowance against the deferred tax asset net of the AMT credit at December 31, 2017 primarily due to cumulative losses incurred during the 3 years ended December 31,
2017. The total valuation allowance December 31, 2018 was $11.5 million, and $12.1 million at December 31, 2017.
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 25, 2019, Mr. Salas individually and through Dolphin controls 5,294,241 shares of the Company’s common stock and
had options granting him the right to acquire an additional 5,000 shares of common stock. His ownership and voting control of approximately 49.8% 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 25, 2019, the Company had 10,644,252 shares of common stock outstanding of which 5,459,621 shares were held by officers,
directors, and affiliates. In addition, options to purchase 15,000 shares of unissued common stock were granted under the Tengasco, Inc. Stock Incentive Plan all of which were vested at March 25, 2019.
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 10.6 million shares have been issued. The
potential issuance of the approximately 89.4 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.
None.
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 $4,038 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, 2018, 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, 2018 contained 15,302 gross acres (11,742 net acres) in central Kansas. Of these acres, 13,870
gross acres (11,447 net acres) were held by production.
The Kansas leases 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 terms for most of the Company’s newer leases in Kansas are from three to five years.
During 2018, the Company participated in drilling two operated wells, one of which was completed as a producing well, and three
non-operated wells, none of which were completed as producing wells. All of the Company’s current reserve value, production, oil and gas revenue, and future development objectives result from the Company’s ongoing interest in Kansas. 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 2018 production and reserve values as of December 31, 2018.
Production by County
|
Area
|
Gross
Production
MBOE
|
Average Net
Revenue
Interest
|
Percentage
of Total Oil
Production
|
|||||||||
|
Rooks County, KS
|
80.4
|
0.820700
|
66.9
|
%
|
||||||||
|
Trego County, KS
|
15.5
|
0.804067
|
12.9
|
%
|
||||||||
|
Ellis County, KS
|
6.3
|
0.801706
|
5.2
|
%
|
||||||||
|
Barton County, KS
|
5.5
|
0.815019
|
4.6
|
%
|
||||||||
|
Graham County, KS
|
3.7
|
0.861997
|
3.1
|
%
|
||||||||
|
Russell County, KS
|
3.0
|
0.856987
|
2.5
|
%
|
||||||||
|
Rush County, KS
|
2.2
|
0.859672
|
1.8
|
%
|
||||||||
|
Osborne County, KS
|
1.4
|
0.588648
|
1.2
|
%
|
||||||||
|
Pawnee County, KS
|
1.3
|
0.797860
|
1.1
|
%
|
||||||||
|
Stafford County, KS
|
0.9
|
0.716073
|
0.7
|
%
|
||||||||
|
Total
|
120.2
|
100.0
|
%
|
|||||||||
Reserve Value by County Discounted at 10% (in thousands)
|
Area
|
Proved
Developed |
Proved
Undeveloped |
Proved
Reserves |
% of
Total |
||||||||||||
|
Rooks County, KS
|
$
|
9,359
|
$
|
118
|
$
|
9,477
|
67.8
|
%
|
||||||||
|
Trego County, KS
|
1,702
|
363
|
2,065
|
14.8
|
%
|
|||||||||||
|
Barton County, KS
|
805
|
—
|
805
|
5.7
|
%
|
|||||||||||
|
Graham County, KS
|
506
|
222
|
728
|
5.2
|
%
|
|||||||||||
|
Ellis County, KS
|
406
|
—
|
406
|
2.9
|
%
|
|||||||||||
|
Rush County, KS
|
235
|
—
|
235
|
1.7
|
%
|
|||||||||||
|
Russell County, KS
|
135
|
—
|
135
|
1.0
|
%
|
|||||||||||
|
Pawnee County, KS
|
70
|
—
|
70
|
0.5
|
%
|
|||||||||||
|
Osborne County, KS
|
40
|
—
|
40
|
0.3
|
%
|
|||||||||||
|
Stafford County, KS
|
15
|
—
|
15
|
0.1
|
%
|
|||||||||||
|
Ness County, KS
|
—
|
—
|
—
|
—
|
%
|
|||||||||||
|
Logan County, KS
|
—
|
—
|
—
|
—
|
%
|
|||||||||||
|
Total
|
$
|
13,273
|
$
|
703
|
$
|
13,976
|
100.0
|
%
|
||||||||
Reserve Analyses
The Company’s estimated total net proved reserves of oil and natural gas as of December 31, 2018 and 2017, 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, 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
|
||||||||
Total Proved Reserves as of December 31, 2017
|
Producing
|
Non-producing
|
Undeveloped
|
Total
|
|||||||||||||
|
Oil (MBbl)
|
774
|
58
|
38
|
870
|
||||||||||||
|
Future net cash flows before income taxes discounted at 10% (in thousands)
|
$
|
7,065
|
$
|
1,082
|
$
|
23
|
$
|
8,170
|
||||||||
Historically, all drilling has primarily been funded by cash flows from operations with supplemental funding provided by the Company’s
credit facility.
The oil price after basis adjustments used in our December 31, 2018 reserve valuation was $60.21 per Bbl compared to $45.83 per Bbl used
in our December 31, 2017 reserve valuation. The primary factor causing the increase in proved producing and undeveloped reserve volumes from December 31, 2017 levels was related to increased 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, 2018. 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 three fiscal years the volumes of oil produced from operated properties, the Company’s
operating costs, and the Company’s average sales prices for its oil. The net production volumes excluded volumes produced to royalty interest or other parties’ working interest.
|
Kansas
|
||||||||||||||||||||||||||||
|
Gross
Production
|
Net
Production
|
Cost of Net
Production
|
Average Sales Price
|
|||||||||||||||||||||||||
|
Years Ended
December 31, |
Oil
(MBbl) |
Gas
(MMcf) |
Oil
(MBbl) |
Gas
(MMcf) |
(Per BOE)
|
Oil
(Bbl) |
Gas
(Per Mcf) |
|||||||||||||||||||||
|
2018
|
120
|
—
|
98
|
—
|
$
|
32.52
|
$
|
59.48
|
—
|
|||||||||||||||||||
|
2017
|
122
|
—
|
99
|
—
|
$
|
29.77
|
$
|
45.43
|
—
|
|||||||||||||||||||
Oil and Gas Drilling Activities
During 2018, the Company participated in drilling two operated wells, one of which was completed as a producing well, and three
non-operated wells, none of which were completed as producing wells. All of the Company’s current reserve value, production, oil and gas revenue, and future development objectives result from the Company’s ongoing interest in Kansas.
Gross and Net Wells
The following tables set forth the fiscal years ending December 31, 2018 and 2017 the number of gross and net development wells drilled by
the Company. The term gross wells means the total number of wells in which the Company owns an interest, while the term net wells means the sum of the fractional working interest the Company owns in the gross wells.
|
For Years Ending December 31,
|
||||||||||||||||
|
2018
|
2017
|
|||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||
|
Kansas
|
||||||||||||||||
|
Productive Wells
|
1
|
0.90
|
1
|
0.15
|
||||||||||||
|
Dry Holes
|
4
|
1.50
|
—
|
—
|
||||||||||||
Productive Wells
As of December 31, 2018, the Company held a working interest in 199 gross wells, including interest in 5 properties operated by others,
and 192 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, 2018 the Company owned and operated working interests in the following developed and undeveloped oil and gas acreage.
The term gross acres means the total number of acres in which the Company owns an interest, while the term net acres means the sum of the fractional working interest the Company owns in the gross acres, less the interest of royalty owners.
|
Developed
|
Undeveloped
|
Total
|
||||||||||||||||||||||
|
Gross Acres
|
Net Acres
|
Gross Acres
|
Net Acres
|
Gross Acres
|
Net Acres
|
|||||||||||||||||||
|
Kansas
|
13,870
|
11,447
|
1,432
|
295
|
15,302
|
11,742
|
||||||||||||||||||
The following table identifies the number of gross and net undeveloped acres as of December 31, 2018 that will expire, by year, unless
production is established before lease expiration or unless the lease is renewed.
|
2021
|
Total
|
|||||||
|
Gross Acres
|
1,432
|
1,432
|
||||||
|
Net Acres
|
295
|
295
|
||||||
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.
Not Applicable.
PART II
|
ITEM 5.
|
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
|
Market Information
The Company’s common stock is listed on the NYSE American exchange under the symbol TGC. The range of high and low sales prices for
shares of common stock of the Company as reported on the NYSE American during the fiscal years ended December 31, 2018 and December 31, 2017 are set forth below.
|
For the Quarters Ending
|
High
|
Low
|
||||||
|
March 31, 2018
|
$
|
1.02
|
$
|
0.59
|
||||
|
June 30, 2018
|
$
|
0.94
|
$
|
0.60
|
||||
|
September 30, 2018
|
$
|
2.47
|
$
|
0.72
|
||||
|
December 31, 2018
|
$
|
1.33
|
$
|
0.70
|
||||
|
March 31, 2017
|
$
|
0.76
|
$
|
0.37
|
||||
|
June 30, 2017
|
$
|
1.56
|
$
|
0.39
|
||||
|
September 30, 2017
|
$
|
0.83
|
$
|
0.55
|
||||
|
December 31, 2017
|
$
|
1.19
|
$
|
0.57
|
||||
Holders
As of March 25, 2019, the number of shareholders of record of the Company’s common stock was 284 and management believes that there are
approximately 5,000 beneficial owners of the Company’s common stock.
Dividends
The Company did not pay any dividends with respect to the Company’s common stock in 2018 or 2017 and has no present plans to declare any
dividends with respect to its common stock.
Recent Sales of Unregistered Securities
During the fourth quarter of fiscal 2018, the Company did not sell or issue any unregistered securities. Any unregistered equity
securities that were sold or issued by the Company during the first three quarters of fiscal 2018 were previously reported in Reports filed by the Company with the SEC.
Purchases of Equity Securities by the Company and Affiliated Purchasers
Neither the Company nor any of its affiliates repurchased any of the Company’s equity securities during 2018.
Equity Compensation Plan Information
See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matter” for information regarding the
Company’s equity compensation plans.
Not Applicable.
Results of Operations
The Company reported net income from continuing operations of $442,000 or $0.04 per share in 2018 compared to a net loss of $(603,000) or
$(0.06) per share in 2017.
The Company realized revenues of approximately $5.9 million in 2018 compared to $4.7 million in 2017. During 2018, revenues increased
approximately $1.2 million of which $1.4 million of this increase related to a $14.05 per barrel increase in the average oil price received from $45.43 per barrel received in 2017 to $59.48 per barrel received in 2018. This was partially offset by a
$192,000 decrease related to a decrease in oil sales volumes from 102.4 MBbl in 2017 to 98.2 MBbl in 2018. The more significant production declines were experienced in the Albers, Albers B, Coddington, Croffoot B, McElhaney, McElhaney A, Veverka B,
and Veverka C leases. These decreases were primarily due to natural declines. These production declines were partially offset by certain production increases as a result of polymers performed in late Q2 and early Q3 of 2018 and completion of the
BSU #1-30 well in Q4 2018.
The Company’s production costs and taxes were approximately $3.6 million in 2018 compared to $3.4 million in 2017. The $147,000 increase
in 2018 was primarily related to a $50,000 increase in chemical cost, a $44,000 increase in compensation expense as a result of reinstating compensation to pre-reduction levels as a result of increased oil prices, and a $37,000 increase in pumping
charges, partially offset by a $99,000 decrease primarily related to an amendment to the 2016 Delaware franchise taxes recorded in the third quarter of 2017. The remainder of the increase was primarily related to miscellaneous repairs to wells,
equipment, and roads.
Depreciation, depletion, and amortization was approximately $795,000 in 2018 compared to $862,000 in 2017. The $67,000 decrease in 2018
was primarily due to a $42,000 decrease related to a decrease in the oil and gas depletion rate due principally to an increase in reserve volume at December 31, 2018 compared to reserve volumes at December 31, 2017, and a $33,000 decrease related to
lower sales volumes.
The Company’s general and administrative cost was approximately $1.25 million in 2018 compared to $1.17 million in 2017. The $74,000
increase in 2018 was primarily related to a $39,000 increase in compensation expense as a result of reinstating compensation to pre-reduction levels as a result of increased oil prices, a $31,000 increase in legal and accounting costs, and a $30,000
increase in engineering and reserve valuation consulting costs.
The Company performed its assessment for impairment during 2017 and 2018. No impairments of oil and gas properties or other assets
resulted from the Company’s assessment.
Net interest expense was $5,000 in 2018 compared to $53,000 in 2017. The $48,000 decrease during 2018 was primarily related to a decrease
in the credit facility, interest paid in 2017 related to the amendment of the 2016 franchise taxes, and a reduction in loan amortization costs. The Company’s credit facility was paid off in February 2017.
Other income (expense) was $157,000 in 2018 compared to $0 in 2017. 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 2018 and 2017, the Company did not have any open derivative positions.
The Company recorded an income tax benefit of $17,000 and $242,000 in 2018 and 2017, respectively. The income tax benefit was due to
releasing 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, 2018 and December 31, 2017 primarily due to cumulated losses incurred during the 3
years ended December 31, 2017.
Liquidity and Capital Resources
At December 31, 2018, 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, 2018, the Company’s borrowing base was $3 million, subject to a credit limit based on current covenants of approximately $2.74 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, 2018, 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, 2018, the interest rate on this credit facility was 6.00%. The Company was in compliance with all covenants as of December 31, 2018.
On August 24, 2018, 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 increase the borrowing base to $3 million, subject to a credit limit based on current covenants of approximately $2.74 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 5.50% at the date of the amendment. The maximum line of credit of the Company under the Prosperity Bank credit facility remained
$50 million.
On March 21, 2018, the Company’s senior credit facility with Prosperity
Bank after Prosperity Bank’s review of the Company’s owned producing properties was amended to increase the borrowing base to $2 million and the maturity date was extended to July 31, 2020. The borrowing base remained subject to the existing
periodic redetermination provisions in the credit facility. The interest rate remained prime plus 0.50% per annum. This rate was 5.00% 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, 2018 and December 31, 2017. The next borrowing base review will take
place in April 2019.
Net cash provided by operating activities by continuing operations was $1.3 million in 2018, and $113,000 in 2017. Cash flow used in
working capital during 2018 was $79,000, and $319,000 during 2017. The change in cash used in operating activities during 2018 was primarily related to increased revenues as a result of higher oil prices, and changes in working capital.
Net cash used in investing activities was $1.0 million in 2018 compared to $179,000 in 2017. The $844,000 increase in cash used in
investing activities during 2018 was due primarily to drilling and polymer costs incurred during 2018.
Net cash used by in financing activities was $42,000 in 2018 compared to
net cash provided by financing activities was $134,000 in 2017. The $176,000 decrease in net cash provided by financing activities in 2018 was primarily related to proceeds from the Company’s rights offering which closed on February 2,
2017.
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, 2018, and 2017 (in thousands):
|
Year Ended
|
Year Ended
|
|||||||
|
December 31, 2018
|
December 31,2017
|
|||||||
|
Revenue (in thousands):
|
||||||||
|
Crude oil
|
$
|
5,840
|
$
|
4,653
|
||||
|
Salt water disposal fees
|
31
|
30
|
||||||
|
Total
|
$
|
5,871
|
$
|
4,683
|
||||
There were no natural gas imbalances at December 31, 2018 or December 31, 2017.
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 $23,000 and $0 in unevaluated properties as of December 31, 2018 and 2017,
respectively. 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, 2018 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 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 Update 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 in this Update is
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. Upon adoption on January 1, 2019, the Company anticipates that it will record right-of-use
assets and liabilities associated with operating leases of approximately $100,000.
Contractual Obligations
The following table summarizes the Company’s contractual obligations due by period as of December 31, 2018 (in thousands):
|
Contractual Obligations
|
Total
|
2019
|
2020
|
2021
|
||||||||||||
|
Long-Term Debt Obligations1
|
$
|
124
|
$
|
51
|
$
|
47
|
$
|
26
|
||||||||
|
Operating Lease Obligations
|
82
|
49
|
33
|
—
|
||||||||||||
|
Estimated Interest on Long-Term Debt Obligations
|
12
|
8
|
3
|
1
|
||||||||||||
|
Total
|
$
|
218
|
$
|
108
|
$
|
83
|
$
|
27
|
||||||||
| (1) |
The credit facility with Prosperity Bank had a zero balance at December 31, 2018.
|
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 2018 ranged from a low of $43.79 per barrel to a high of $65.70 per barrel.
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 2018 or 2017, but may participate in derivative activities in the future.
Interest Rate Risk
At December 31, 2018, the Company had debt outstanding of approximately $124,000, none of which was owed on its credit facility with
Prosperity Bank. As of December 31, 2018, 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, 2018 was 6.00%. The Company’s remaining debt
of $124,000 has fixed interest rates ranging from 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, 2018 or 2017.
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.
The financial statements and supplementary data commence on page F-1.
None.
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, 2018. 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, 2018.
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, 2018, 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.
On January 2, 2019, 4,962 common shares were issued in the aggregate to the Company’s three directors and CFO and interim CEO. This
issuance will result in compensation expense of approximately $4,714 to be recorded during the quarter ended March 31, 2019.
In January 2019, the Company sold its equipment inventory for $150,000.
The Company will record a gain on this sale of $45,000 during the quarter ended March 31, 2019.
PART III
Identification of Directors and Executive Officers
|
NAME
|
POSITIONS HELD
|
DATE OF INITIAL
ELECTION OR
DESIGNATION
|
AGE
|
|||
|
Matthew K. Behrent
|
Director
|
3/27/2007
|
48
|
|||
|
Peter E. Salas
|
Director;
|
10/8/2002
|
64
|
|||
|
Chairman of the Board
|
10/21/2004
|
|||||
|
Richard M. Thon
|
Director
|
11/22/2013
|
63
|
|||
|
Michael J. Rugen
|
Chief Financial Officer;
|
9/28/2009
|
58
|
|||
|
|
Chief Executive Officer (interim)
|
6/24/2013
|
||||
|
Cary V. Sorensen
|
Vice-President; General Counsel; Secretary
|
7/9/1999
|
70
|
|||
Business Experience
Directors
Matthew K. Behrent is currently the Executive Vice President, Corporate Development of EDCI Holdings, Inc., a company that is currently
engaged in carrying out a plan of dissolution. Before joining EDCI in June, 2005, Mr. Behrent was an investment banker, working as a Vice-President at Revolution Partners, a technology focused investment bank in Boston, from March 2004 until June
2005 and as an associate in Credit Suisse First Boston Corporation’s technology mergers and acquisitions group from June 2000 until January 2003. From June 1997 to May 2000, Mr. Behrent practiced law, most recently with Cleary, Gottlieb, Steen &
Hamilton in New York, advising financial sponsors and corporate clients in connection with financings and mergers and acquisitions transactions. Mr. Behrent received his J.D. from Stanford Law School in 1997, and his B.A. in Political Science and
Political Theory from Hampshire College in 1992. He became a Director of the Company on March 27, 2007. The experience, qualifications, attributes, and skills gained by Mr. Behrent in these sophisticated legal and financial positions directly apply
to and support the financial oversight of the Company’s operations and lead to the conclusion that Mr. Behrent should serve as a Director of the Company.
Peter E. Salas has been President of Dolphin Asset Management Corp. and its related companies since he founded it in 1988. Prior to
establishing Dolphin, he was with J.P. Morgan Investment Management, Inc. for ten years, becoming Co-manager, Small Company Fund and Director-Small Cap Research. He received an A.B. degree in Economics from Harvard in 1978. Mr. Salas was elected to
the Board of Directors on October 8, 2002. The business experience, attributes, and skills gained by Mr. Salas in these sophisticated financial positions, together with his service as director of other public companies and his capacity as
controlling person of the Company’s largest shareholder directly apply to and support his qualification as a director, and lead to the conclusion that Mr. Salas should serve as a Director of the Company.
Richard M. Thon began a career with ARAMARK Corporation in 1987. ARAMARK is based in Philadelphia, has 270,000 employees worldwide, and
provides food services, facilities management, and uniform and career apparel to health care institutions, universities, and businesses in 23 countries. Mr. Thon served in various capacities in the Corporate Finance Department of ARAMARK culminating
with the position of Assistant Treasurer when he retired in June 2002. His responsibilities included bank credit agreements, public debt issuance, interest rate risk management, foreign subsidiary credit agreements, foreign exchange, letters of
credit, insurance finance, off-balance-sheet finance, and real estate and equipment leasing. Prior to joining ARAMARK, Mr. Thon was a Vice President in the International Department of Mellon Bank. Since his retirement in 2002, Mr. Thon has served in
a variety of volunteer charitable and civic activities. Mr. Thon received a B.A. in Economics degree from Yale College in 1977 and a Masters of Business Administration degree in Finance from The Wharton School, University of Pennsylvania in 1979.
Mr. Thon’s experience in the fields of banking and finance directly apply to the business needs of the Company and lead to the conclusion that he will provide significant benefit to the Board and that he is qualified to serve as a Director of the
Company.
Officers
Michael J. Rugen was named Chief Financial Officer of the Company in September 2009 and as interim Chief Executive Officer in June 2013.
He is a certified public accountant (Texas) with over 35 years of experience in exploration, production and oilfield service. Prior to joining the Company, Mr. Rugen spent 2 years as Vice President of Accounting and Finance for Nighthawk Oilfield
Services. From 2001 to June 2007, he was a Manager/Sr. Manager with UHY Advisors, primarily responsible for managing internal audit and Sarbanes-Oxley 404 engagements for various oil and gas clients. In 1999 and 2000, Mr. Rugen provided finance and
accounting consulting services with Jefferson Wells International. From 1982 to 1998, Mr. Rugen held various accounting and management positions at BHP Petroleum, with accounting responsibilities for onshore and offshore US operations as well as
operations in Trinidad and Bolivia. Mr. Rugen earned a Bachelor of Science in Accounting in 1982 from Indiana University.
Cary V. Sorensen is a 1976 graduate of the University of Texas School of Law and has undergraduate and graduate degrees from North Texas
State University and Catholic University in Washington, D.C. Prior to joining the Company in July 1999, he had been continuously engaged in the practice of law in Houston, Texas relating to the energy industry since 1977, both in private law firms
and a corporate law department, serving for seven years as senior counsel with the oil and gas litigation department of a Fortune 100 energy corporation in Houston before entering private practice in June, 1996. He has represented virtually all of
the major oil companies headquartered in Houston as well as local distribution companies and electric utilities in a variety of litigated and administrative cases before state and federal courts and agencies in nine states. These matters involved
gas contracts, gas marketing, exploration and production disputes involving royalties or operating interests, land titles, oil pipelines and gas pipeline tariff matters at the state and federal levels, and general operation and regulation of
interstate and intrastate gas pipelines. He has served as General Counsel of the Company since July 9, 1999.
Family and Other Relationships
There are no family relationships between any of the present directors or executive officers of the Company.
Involvement in Certain Legal Proceedings
To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficially of more than
5% of the Company’s common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding.
To the knowledge of management, during the past ten years, unless specifically indicated below with respect to any numbered item, no
present director, executive officer or person nominated to become a director or an executive officer of the Company:
| (1) |
Filed a petition under the federal bankruptcy laws or any state insolvency law, nor had a receiver, fiscal agent or similar officer appointed by a court for the business or
property of such person, or any partnership in which he or she was a general partner at or within two years before the time of such filing, or any corporation or business association of which he or she was an executive officer at or
within two years before the time of such filing; provided however that:
|
| a. |
the Company’s Chief Financial Officer Michael J. Rugen during 2007 through mid-2009 was Vice President of Accounting and Finance for Nighthawk Oilfield Services in Houston,
Texas (Nighthawk); Nighthawk filed for bankruptcy protection under Chapter 7 of the bankruptcy laws on July 10, 2009 and such fact was affirmatively disclosed to the Company’s Board before Mr. Rugen was appointed to the position of Chief
Financial Officer of the Company in September, 2009, and the Board determined that the circumstances surrounding bankruptcy filing did not disclose any reason to question the integrity or qualifications of Mr. Rugen for the position of
Chief Financial Officer of the Company; and
|
| b. |
Peter E. Salas, a director of the Company and Chairman of the Board of the Company was the chief executive officer of Boston Restaurant Associates, Inc. when that company
filed a Chapter 11 reorganization plan under federal bankruptcy laws on May 20, 2015. The plan of reorganization became effective on August 31, 2015 and Mr. Salas has remained the chief executive officer and sole director of that company
since the reorganization
|
| (2) |
Was convicted in a criminal proceeding or named the subject of a pending criminal proceeding (excluding traffic violations and other minor offenses);
|
| (3) |
Was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any court of competent jurisdiction, permanently or temporarily
enjoining him or her from or otherwise limiting the following activities: (a) acting as a futures commission merchant, introducing broker, commodity trading advisor, commodity pool operator, floor broker, leverage transaction merchant,
any other person regulated by the Commodity Futures Trading Commission (“CFTC”), or an associated person of any of the foregoing, or as an investment adviser, underwriter, broker or dealer in securities, or as an affiliated person,
director or employee of any investment company, bank, savings and loan association or insurance company, or engaging in or continuing any conduct or practice in connection with such activity; (b) engaging in any type of business practice;
or (c) engaging in any activity in connection with the purchase or sale of any security or commodity or in connection with any violation of federal or state securities laws or federal commodities laws;
|
| (4) |
Was the subject of any order, judgment or decree, not subsequently reversed, suspended or vacated, of any Federal or State authority barring, suspending or otherwise limiting
him or her for more than 60 days from engaging in any activity described in paragraph 3(a) above, or being associated with any persons engaging in any such activity;
|
| (5) |
Was found by a court of competent jurisdiction in a civil action or by the SEC to have violated any federal or state securities law, and the judgment in such civil action or
finding by the SEC has not been subsequently reversed, suspended, or vacated;
|
| (6) |
Was found by a court of competent jurisdiction in a civil action or by the CFTC to have violated any federal commodities law, and the judgment in such civil action or
finding by the CFTC has not been subsequently reversed, suspended, or vacated;
|
| (7) |
Was the subject of, or a party to, any federal or state judicial or administrative order, judgment, decree, or finding, not subsequently reversed, suspended or vacated,
relating to an alleged violation of: (i) any federal or state securities or commodities law or regulation; (ii) any law or regulation respecting financial institutions or insurance companies including but not limited to a temporary or
permanent injunction, order of disgorgement or restitution, civil money penalty or temporary or permanent cease and desist order, or removal or prohibition order; or (iii) any law or regulation prohibiting mail or wire fraud or fraud in
connection with any business entity; or
|
| (8) |
Was the subject of, or a party to, any sanction or order, not subsequently reversed, suspended or vacated, of any self-regulatory organization (as defined in Section 3(a)(26)
of the Exchange Act [15 U.S.C. 78c(a)(26)], any registered entity (as defined in Section 1(a)(29) of the Commodity Exchange Act [7 U.S.C. 1(a)(29)], or any equivalent exchange, association, entity or organization that has disciplinary
authority over its members or persons associated with a member.
|
Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Securities Exchange Act of 1934 requires the Company’s executive officers, directors and persons who beneficially own
more than 10% of the Company’s common stock to file initial reports of ownership and reports of changes in ownership with the SEC no later than the second business day after the date on which the transaction occurred unless certain exceptions apply.
In fiscal 2018, the Company, its officers, directors, and shareholders owning more than 10% of its common stock were not delinquent in filing of any of their Form 3, 4, and 5 reports.
Code of Ethics
The Company’s Board of Directors has adopted a Code of Ethics that applies to the Company’s financial officers and executives officers,
including its Chief Executive Officer and Chief Financial Officer. The Company’s Board of Directors has also adopted a Code of Conduct and Ethics for Directors, Officers and Employees. A copy of these codes can be found at the Company’s internet
website at www.tengasco.com. The Company intends to disclose any amendments to its Codes of Ethics, and any waiver from a provision of the Code of Ethics granted to the Company’s President, Chief Financial Officer or persons performing similar
functions, on the Company’s internet website within five business days following such amendment or waiver. A copy of the Code of Ethics can be obtained free of charge by writing to Cary V. Sorensen, Secretary, Tengasco, Inc., 8000 E. Maplewood Ave.,
Suite 130, Greenwood Village, CO 80111.
Audit Committee
During 2018, directors Matthew K. Behrent and Richard M. Thon were the
members of the Board’s Audit Committee. Mr. Behrent was the Chairman of the Committee and the Board of Directors determined that both Mr. Behrent and Mr. Thon were each an “audit committee financial expert” as defined by applicable Securities and
Exchange Commission (“SEC”) regulations and the NYSE American Rules. Each of the members of the Audit Committee met the independence and experience requirements of the NYSE American Rules, the applicable Securities Laws, and the
regulations and rules promulgated by the SEC. The Audit Committee met each quarter and a total of four (4) times in Fiscal 2018 with the Company’s auditors, including discussing the
audit of the Company’s year-end financial statements.
The Audit Committee adopted an Audit Committee Charter during fiscal 2001. In 2004, the Board adopted an amended Audit Committee Charter,
a copy of which is available on the Company’s internet website, www.tengasco.com. The Audit Committee Charter fully complies with the requirements of the NYSE American Rules. The Audit Committee reviews and reassesses the Audit Committee Charter
annually.
The Audit Committee’s functions are:
| · |
To review with management and the Company’s independent auditors the scope of the annual audit and quarterly statements, significant financial reporting issues and judgments
made in connection with the preparation of the Company’s financial statements;
|
| · |
To review major changes to the Company’s auditing and accounting principles and practices suggested by the independent auditors;
|
| · |
To monitor the independent auditor’s relationship with the Company;
|
| · |
To advise and assist the Board of Directors in evaluating the independent auditor’s examination;
|
| · |
To supervise the Company’s financial and accounting organization and financial reporting;
|
| · |
To nominate, for approval of the Board of Directors, a firm of certified public accountants whose duty it is to audit the financial records of the Company for the fiscal year
for which it is appointed; and
|
| · |
To review and consider fee arrangements with, and fees charged by, the Company’s independent auditors.
|
Changes in Board Nomination Procedures
In 2018, there were no changes to the procedures adopted by the Board for nominations for the Board of Directors. Those procedures were
last set forth in the Company’s Proxy Statement filed on October 3, 2014 for the Company’s Annual Meeting held on November 14, 2014 and are posted on the Company’s internet website at www.tengasco.com. In the event of any such amendment to the
procedures, the Company intends to disclose the amendments on the Company’s internet website within five business days following such amendment.
Executive Officer Compensation
The following table sets forth a summary of all compensation awarded to, earned or paid to, the Company’s Chief Executive Officer, Chief
Financial Officer, other executive officers, and employees whose compensation exceeded $100,000 during fiscal years ended December 31, 2018 and December 31, 2017.
SUMMARY COMPENSATION TABLE
|
Name and Principal Position
|
Year
|
Salary
($) |
Bonus
($) |
Stock
Awards
($) |
All Other
Compensation2
($) |
Total
($) |
||||||||||||||||
|
Michael J. Rugen,
|
2018
|
184,213
|
21,821
|
15,097
|
7,482
|
228,613
|
||||||||||||||||
|
Chief Financial Officer
|
2017
|
163,857
|
19,276
|
9,149
|
6,673
|
198,955
|
||||||||||||||||
|
Chief Executive Officer (interim)3
|
||||||||||||||||||||||
|
Cary V. Sorensen,
|
2018
|
87,050
|
—
|
—
|
3,550
|
90,600
|
||||||||||||||||
|
General Counsel
|
2017
|
81,900
|
—
|
—
|
3,454
|
85,354
|
||||||||||||||||
| (2) |
The amounts in this column consist of the Company’s matching contributions to its 401 (k) plan and the portion of company-wide group term life insurance premiums allocable to
these named executive officers.
|
| (3) |
Mr. Rugen was appointed interim Chief Executive Officer on June 28, 2013. The bonus and stock award information for Mr. Rugen for 2018 and 2017 represents his compensation
for his services as CEO.
|
Outstanding Equity Awards at Fiscal Year-End
|
OPTION AWARDS
|
||||||||||||||||
|
Name
|
Number of securities
underlying unexercised
options exercisable |
Number of securities
underlying unexercised
options unexercisable |
Option exercise
price |
Option
expiration date |
||||||||||||
|
Michael J. Rugen
|
—
|
—
|
$
|
—
|
||||||||||||
|
Cary V. Sorensen
|
—
|
—
|
$
|
—
|
||||||||||||
Option and Award Exercises
No other options were exercised during 2018 or 2017.
Employment Contracts and Compensation Agreements
On September 18, 2013, the Company and its Chief Financial Officer and interim Chief Executive Officer Michael J. Rugen entered into a
written Compensation Agreement as reported on Form 8-K filed on September 24, 2013. Under the terms of the Compensation Agreement, Mr. Rugen’s annual salary will increase from $150,000 to $170,000 per year in his capacity as Chief Financial Officer,
and he will receive a bonus of $7,500 per quarter for each quarter during which he also serves as interim Chief Executive Officer. At June 1, 2014, Mr. Rugen’s salary was increased to $199,826 per year in his capacity as Chief Financial Officer, the
quarterly bonus received while in the capacity as interim Chief Financial Officer was increased to $8,815 per quarter. The increases at June 1, 2014 were for cost of living adjustments related to the relocation of the corporate office from Knoxville
to Greenwood Village. The Compensation agreement is not an employment contract, but does provide that in the event Mr. Rugen were terminated without cause, he would receive a severance payment in the amount of six month’s salary in effect at the
time of any such termination.
On February 25, 2015, the Company and its Vice President, General Counsel, and Corporate Secretary Cary V. Sorensen entered into a written
Compensation Agreement as reported on Form 8-K filed on February 19, 2015. Under the terms of the Compensation Agreement, effective March 2, 2015, Mr. Sorensen’s annual salary will be reduced from $137,500 to $91,000 in consideration of the
Company’s agreement to permit Mr. Sorensen to serve as a full time employee from a virtual office in Galveston, Texas with presence in the Denver area headquarters as required. He will remain eligible for certain existing benefits: 401-K plan, bonus
potential; Company-paid state bar membership dues and charges, and mobile phone charges. The Company also pays reasonable and customary office operating expenses. The Company would pay for business travel on a mileage basis and out of pocket travel
costs. However, as to health insurance, Mr. Sorensen will obtain a combination of private/governmental health and disability insurance in lieu of the Company plans, with the Company reimbursing up to $13,000 per year in premiums incurred by him.
On February 19, 2015, in response to the global market factors affecting revenues from sales of the Company’s production of crude oil,
the Board of Directors of the Company implemented reductions in the compensation of the Company’s officers.
As to the Company’s Chief Financial Officer and interim Chief Executive Officer Michael J. Rugen, Mr. Rugen’s salary as CFO and bonus as
CEO was reduced effective February 2, 2015 by 18% from current levels, or about $42,000 per year. The 18% reduction will remain in place until the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published
by the U.S. Energy Information Administration meets or exceeds $70 per barrel when his compensation shall revert to the levels in place before the reductions became effective. In May 2018, oil prices as so calculated exceeded $70 and compensation
reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information
Administration meets or exceeds $85 per barrel, all previous reductions made will be reimbursed to Mr. Rugen if he is still employed by the Company. Mr. Rugen expressly consented to this reduction as not constituting a “termination without Cause”
under the terms of his Compensation Agreement dated September 18, 2013 but permitting him to invoke that provision in the event prices do recover as set out above but the compensation reduction is not rescinded or the reductions are not repaid.
As to the Company’s Vice President, General Counsel, and Corporate Secretary Cary V Sorensen, the Company and Mr. Sorensen reached
agreement on February 25, 2015 that as of March 2, 2015 his annual salary would be set at $91,000 per annum, a reduction from his current salary of $137,500 per annum as described above. In addition, Mr. Sorensen’s $91,000 salary will be reduced
effective March 2, 2015 by 10%. In like manner as set out above for Mr. Rugen, the 10% reduction on Mr. Sorensen’s salary will remain in place until the market price of crude oil, calculated as a thirty day trailing average of WTI postings as
published by the U.S. Energy Information Administration meets or exceeds $70 per barrel when his salary shall revert to $91,000 per annum. In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before
the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all
previous reductions made from the $91,000 salary level will be reimbursed to Mr. Sorensen if he is still employed by the Company.
There are presently no other employment contracts relating to any member of management. However, depending upon the Company’s operations
and requirements, the Company may offer long-term contracts to executive officers or key employees in the future.
Compensation and Stock Option Committee
The members of the Compensation/Stock Option Committee during 2018 were Matthew K. Behrent and Richard M. Thon, with Mr. Thon acting as
Chairman. Messrs. Behrent and Thon meet the current independence standards established by the NYSE American Rules to serve on this Committee.
The Board of Directors has adopted a charter for the Compensation/Stock Option Committee which is available at the Company’s internet
website, www.tengasco.com.
The Compensation/Stock Option Committee’s functions, in conjunction with the Board of Directors, are to provide recommendations with
respect to general and specific compensation policies and practices of the Company for directors, officers and other employees of the Company. The Compensation/Stock Option Committee expects to periodically review the approach to executive
compensation and to make changes as competitive conditions and other circumstances warrant and will seek to ensure the Company’s compensation philosophy is consistent with the Company’s best interests and is properly implemented. The Committee
determines or recommends to the Board of Directors for determination the specific compensation of the Company’s Chief Executive Officer and all of the Company’s other officers. Although the Committee may seek the input of the Company’s Chief
Executive Officer in determining the compensation of the Company’s other executive officers, the Chief Executive Officer may not be present during the voting or deliberations with respect to his compensation. The Committee may not delegate any of its
responsibilities unless it is to a subcommittee formed by the Committee, but only if such subcommittee consists entirely of directors who meet the independence requirements of the NYSE American Rules.
The Compensation/Stock Option Committee is also charged with administering the Tengasco, Inc. Stock Incentive Plan (the “Stock Incentive
Plan”). The Compensation/Stock Option Committee has complete discretionary authority with respect to the awarding of options, stock, and Stock Appreciation Rights (“SARs”), under the Stock Incentive Plan, including, but not limited to, determining
the individuals who shall receive options and SARs; the times when they shall receive them; whether an option shall be an incentive or a non-qualified stock option; whether an SAR shall be granted separately, in tandem with or in addition to an
option; the number of shares to be subject to each option and SAR; the term of each option and SAR; the date each option and SAR shall become exercisable; whether an option or SAR shall be exercisable in whole, in part or in installments and the
terms relating to such installments; the exercise price of each option and the base price of each SAR; the form of payment of the exercise price; the form of payment by the Company upon the exercise of an SAR; whether to restrict the sale or other
disposition of the shares of common stock acquired upon the exercise of an option or SAR; to subject the exercise of all or any portion of an option or SAR to the fulfillment of a contingency, and to determine whether such contingencies have been
met; with the consent of the person receiving such option or SAR, to cancel or modify an option or SAR, provided such option or SAR as modified would be permitted to be granted on such date under the terms of the Stock Incentive Plan; and to make all
other determinations necessary or advisable for administering the Plan.
In May 2018, oil prices as so calculated exceeded $70 and executive compensation reverted to the levels in place before the compensation
reductions became effective. The Committee has the authority to retain a compensation consultant or other advisors to assist it in the evaluation of compensation and has the sole authority to approve the fees and other terms of retention of such
consultants and advisors and to terminate their services. The Committee did not retain any such consultants or advisors in 2018.
Compensation of Directors
The Board of Directors has resolved to compensate members of the Board of Directors for attendance at meetings at the rate of $250 per
day, together with direct out-of-pocket expenses incurred in attendance at the meetings, including travel. The Directors, as of the date of this Report, have waived all such fees due to them for prior meetings.
Members of the Board of Directors may also be requested to perform consulting or other professional services for the Company from time to
time, although at this time no such arrangements are in place. The Board of Directors has reserved to itself the right to review all directors’ claims for compensation on an ad hoc basis.
Board members currently receive fees from the Company for their services as director. They may also from time to time be granted stock
options or common stock under the Tengasco, Inc. Stock Incentive Plan. A separate plan to issue cash and/or shares of stock to independent directors for service on the Board and various committees was authorized by the Board of Directors and approved
by the Company’s shareholders. A copy of that separate plan is posted at the Company’s website at www.tengasco.com. However, no award was made to any independent director under that separate plan in Fiscal 2018.
On February 19, 2015, in response to the global market factors affecting revenues from sales of the Company’s production of crude oil,
the Board of Directors of the Company implemented reductions in the compensation of the Company’s directors. The reductions on the directors’ compensation will remain in place until the market price of crude oil, calculated as a thirty day
trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel when then their compensation will revert to pre-reduction levels. In May 2018, oil prices as so calculated exceeded $70 and
compensation reverted to the levels in place before the reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information
Administration meets or exceeds $85 per barrel, all previous reductions made from pre-reduction compensation levels will be reimbursed to the directors if they are still directors of the Company.
DIRECTOR COMPENSATION FOR FISCAL 2018
| Name |
Fees earned or
paid in cash
($)
|
Stock awards
compensation4
($)
|
Total
($)
|
|||||||||
|
Matthew K. Behrent
|
$
|
12,012
|
$
|
2,300
|
$
|
14,312
|
||||||
|
Richard M. Thon
|
$
|
12,012
|
$
|
2,300
|
$
|
14,312
|
||||||
|
Peter E. Salas
|
$
|
12,012
|
$
|
2,300
|
$
|
14,312
|
||||||
| (4) |
The amounts represented in this column are equal to the aggregate grant date fair value of the award computed in accordance with FASB ASC Topic 718, Compensation-Stock
Compensation, in connection with options granted under the Tengasco, Inc. Stock Incentive Plan. See Note 11 Stock and Stock Options in the Notes to Consolidated Financial Statements included in the Company’s Annual Report on Form 10-K
for the year ended December 31, 2018 for information on the relevant valuation assumptions.
|
As of December 31, 2018, Mr. Behrent held 5,625 unexercised options; Mr. Salas held 5,625 unexercised options; and Mr. Thon held 5,625
unexercised options. The number of unexercised options have been adjusted to reflect the impact of the 1 for 10 reverse stock split approved at the shareholder meeting dated March 21, 2016, effective with trading on March 24, 2016.
|
ITEM 12.
|
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDERS MATTERS
|
The following table sets forth the shareholdings of those persons who own more than 5% of the Company’s common stock as of March 25, 2019
with these computations being based upon 10,644,252 shares of common stock being outstanding as of that date and as to each shareholder, as it may pertain, assumes the exercise of options or warrants granted or held by such shareholder that are
exercisable as of March 26, 2018.
FIVE PERCENT STOCKHOLDERS 5
|
Name and Address
|
Title
|
Number of Shares
Beneficially Owned |
Percent of Class
|
|||||||
|
Dolphin Offshore Partners, L.P.
c/o Dolphin Mgmt. Services, Inc.
P.O. Box 16867
Fernandina Beach, FL 32035
|
Stockholder
|
5,294,241
|
49.7
|
%
|
||||||
| (5) |
Unless otherwise stated, all shares of Common Stock are directly held with sole voting and dispositive power. The shares set forth in the table are as of March 25, 2019.
|
SECURITY OWNERSHIP OF DIRECTORS AND OFFICERS
|
Name and Address
|
Title
|
Number of Shares
Beneficially Owned 6 |
Percent of
Class 7 |
|||||||
|
Matthew K. Behrent (8)
|
Director
|
65,900
|
Less than 1%
|
|||||||
|
Michael J. Rugen (9)
|
Chief Executive Officer
(interim);
Chief Financial Officer
|
51,857
|
Less than 1%
|
|||||||
|
Peter E. Salas (10)
|
Director;
Chairman of the Board
|
5,299,241
|
49.8
|
%
|
||||||
|
Cary V. Sorensen (11)
|
Vice President;
General Counsel;
Secretary
|
23,623
|
Less than 1%
|
|||||||
|
Richard M. Thon (12)
|
Director
|
34,000
|
Less than 1%
|
|||||||
|
All Officers and Directors as a group (13)
|
5,474,621
|
51.4
|
%
|
|||||||
| (6) |
Unless otherwise stated, all shares of common stock are directly held with sole voting and dispositive power. The shares set forth in the table are as of March 25, 2019.
|
| (7) |
Calculated pursuant to Rule 13d-3(d) under the Securities Exchange Act of 1934 based upon 10,644,252 shares of common stock being outstanding as of March 25, 2019. Shares
not outstanding that are subject to options or warrants exercisable by the holder thereof within 60 days of March 25, 2019 are deemed outstanding for the purposes of calculating the number and percentage owned by such stockholder, but not
deemed outstanding for the purpose of calculating the percentage of any other person. Unless otherwise noted, all shares listed as beneficially owned by a stockholder are actually outstanding.
|
| (8) |
Consists of 60,900 shares held directly and vested, fully exercisable options to purchase 5,000 shares.
|
| (9) |
Consists of 51,857 shares held directly.
|
| (10) |
Consists of directly, vested, fully exercisable options to purchase 5,000 shares, 6,000 shares held individually, and 5,288,241 shares held directly by Dolphin Offshore
Partners, L.P. (“Dolphin”). Peter E. Salas is the sole shareholder of and controlling person of Dolphin Mgmt. Services, Inc. which is the general partner of Dolphin.
|
| (11) |
Consists of 23,623 shares held directly.
|
| (12) |
Consists of 29,000 shares held directly and vested, fully exercisable options to purchase 5,000 shares.
|
| (13) |
Consists of 171,380 shares held directly by directors and management, 5,288,241 shares held by Dolphin and vested, and fully exercisable options to purchase 15,000 shares.
|
Change in Control
To the knowledge of the Company’s management, there are no present arrangements or pledges of the Company’s securities which may result in
a change in control of the Company.
Equity Compensation Plan Information
The following table sets forth information regarding the Company’s equity compensation plans as of December 31, 2018.
|
Plan Category
|
Number of securities to
be issued upon exercise
of outstanding options,
warrants and rights(a)
|
Weighted-average
exercise price of
outstanding, options,
warrants and rights(b)
|
Number of securities remaining
available for future issuance under
equity compensation plans
(excluding securities
reflected in column (a)) (c)
|
|||||||||
|
Equity compensation plans approve by security holders 14
|
16,875
|
$
|
3.18
|
301,927
|
||||||||
|
Equity compensation plans not approved by security holders
|
—
|
—
|
—
|
|||||||||
|
Total
|
16,875
|
$
|
3.18
|
301,927
|
||||||||
| (14) |
Refers to Tengasco, Inc. 2018 Stock Incentive Plan (the “2018 Plan”) which was adopted to provide an incentive to key employees, officers, directors and consultants of the
Company and its present and future subsidiary corporations, and to offer an additional inducement in obtaining the services of such individuals. The 2018 Plan contains the same substantive terms of the Company’s previous stock incentive
plan adopted in October, 2000 and as thereafter amended until its expiration on January 10, 2018. The 2018 Plan provided an aggregate number of shares for which shares, options, and stock appreciation rights may be issued under the 2018
Plan equal to the number of shares that were available in the previous plan upon its expiration. The 2018 Plan was approved by a majority of the Company’s shareholders acting on written consent and the shares thereunder were subject to
Registration Statement on Form S-8 filed August 27, 2018.
|
Certain Transactions
During the 4th quarter of 2018, the Company acquired all of Hoactzin’s interest in the drilling program wells for $134,690 as
reported below. The acquisition was authorized by the two nonrelated party directors in accordance with the Company’s related party transaction policy, and was made on the same terms
offered to all participants and accepted by four of the five drilling program participants other than Hoactzin electing to sell their interest to the Company. One participant did not accept the Company’s offer to purchase its interest.
Other than that acquisition, there have been no material transactions, series of similar transactions or currently proposed transactions entered into during 2018 and 2017, to which the Company or any of its subsidiaries was or is to be a party, in
which the amount involved exceeds the lesser of $120,000 or one percent of the average of the Company’s total assets at year-end for its last two completed fiscal years in which any director or executive officer or any security holder who is known
to the Company to own of record or beneficially more than 5% of the Company’s common stock, or any member of the immediate family of any of the foregoing persons, had a material interest.
In this Report on Form 10-K for the year ended December 31, 2018, the Company describes two transactions of the type described above,
that the Company entered into with Hoactzin in 2007 that remained in existence during 2017 and for a portion of the year in 2018. Those two transactions are the “net profits agreement” and the “drilling programs”. In January 2018, the Company
sold its methane facility assets, thereby ending the net profits agreement at the Methane Project. In November 2018, the Company acquired Hoactzin’s interest in the Ten Well Program for $131,290. As noted above, 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. These two 2007 transactions between the Company and Hoactzin are described in Item 1, Business.
The approximate dollar value of the amount of Hoactzin’s interest in each of these two 2007 transactions during each of the years 2017
and a portion of 2018 was as follows: (1) Ten Well Program - $33,000 in 2018; and $31,000 in 2017 (calculated as the total payments attributable to Hoactzin for its program interest); and (2) Net Profits agreement at the Methane Project - $0 in
both 2018 and 2017.
In addition to the two 2007 transactions, Hoactzin also owned a drilling program interest in the Company’s “6 Well Program” in Kansas,
acquired in 2005 by Hoactzin in exchange for surrender of the Company’s promissory notes given by the Company for borrowings to fund the redemption in 2004 of the Company’s three series of preferred stock, all as previously disclosed. In November
2018, the Company acquired Hoactzin’s interest in the 6 Well Program for $3,400. The approximate dollar value of the amount of Hoactzin’s interest in the 6 Well Program was $9,000 in 2018; and $10,000 in 2017 (calculated as the total payments
attributable to Hoactzin for its program interest). Following the acquisition of all Hoactzin’s drilling program interests in November 2018, there will be no interest of Hoactzin in the ten well or six well drilling programs in any future period.
In addition to the above, one transaction of the type described above was entered into in 2007 but has expired by its own
terms. On December 18, 2007, the Company entered into a Management Agreement with Hoactzin to manage on behalf of Hoactzin all of its working interest in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast,
and offshore Texas and offshore Louisiana. As part of the consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin granted to the Company an option to participate in up to a 15% working interest on a dollar for
dollar cost basis in any new drilling or workover activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement. The Management Agreement expired on December 18, 2012.
The Company entered into a transition agreement with Hoactzin whereby the Company will no longer perform operations, but will
administratively assist Hoactzin in becoming operator of record of these wells and administratively assist Hoactzin in the transfer of the corresponding bonds from the Company to Hoactzin. This assistance is primarily related to signing the
necessary documents to effectuate this transition. Hoactzin and its controlling member are indemnifying the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company is the operator of
record on certain of these wells. As of the date of this Report, the Company continues to administratively assist Hoactzin with this transition process.
As operator during the term of the Management Agreement that expired in 2012, the Company routinely contracted in its name for
goods and services with vendors in connection with its operation of the Hoactzin properties. In practice, Hoactzin directly paid these invoices for goods and services that were contracted in the Company’s name. As a result of the operations
performed by Hoactzin in late 2009 and 2010, Hoactzin had significant past due balances to several vendors, a portion of which were included on the Company’s balance sheet. Payables related to these past due and ongoing operations remained
outstanding at December 31, 2017 in the amount of $159,000. The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of December 31, 2017 in its Consolidated Balance Sheets under “Accounts payable –
other” and “Accounts receivable – related party”. However, Hoactzin had not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012. Based on these circumstances, the Company has elected to
establish an allowance in the amount of $159,000 for the balances outstanding at December 31, 2017. This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”. The resulting balances
recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” are $0 at December 31, 2017. At year-end 2018, the Company has determined that the outstanding balances
under these vendor contracts for services or materials provided in 2009 and 2010 are not recoverable against the Company by operation of applicable statutes of limitation or prescription, and consequently, these amounts have been removed from the
Company’s balance sheet at December 31, 2018. This removal also resulted in the Company recording other income in 2018 in the amount of $159,000.
The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by
BSEE during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties. This action called for payment of a civil penalty of $386,000 for failure to provide, upon request, documentation to the BSEE evidencing that certain
safety inspections and tests had been conducted in 2011. On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the civil penalty without reduction. The Company did not further appeal. In the third quarter of
2015, the Company paid the civil penalty and statutory interest thereon from funds borrowed under its credit facility. In the fourth quarter of 2015, the Company received a return of the cash collateral previously provided to RLI Insurance Company.
The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management Agreement, except for those funds used to pay the civil penalty
and interest thereon.
During the second quarter of 2015, the Company received from Hoactzin a copy of an internal analysis prepared by Hoactzin
setting out certain issues that Hoactzin may consider to form the basis of operational and other claims against the Company primarily under the Management Agreement. This analysis raised issues other than the “Incident of Non-Compliance” discussed
above. The Company is discussing this analysis, as well as the civil penalty discussed above, with Hoactzin in an effort to determine whether there is possibility of a reasonable resolution of some or all of these matters on a negotiated basis.
Director Independence
The Rules of the NYSE American (the “NYSE American Rules”) of which the Company is a member require that an issuer, such as the
Company, which is a Smaller Reporting Company pursuant to Regulation S-K Item 10(f)(1), maintain a board of directors of which at least one-half of the members are independent in that they are not officers of the Company and are free of any
relationship that would interfere with the exercise of their independent judgment. The NYSE American Rules also require that as a Smaller Reporting Company, the Company’s Board of Directors’ Audit Committee be comprised of at least two members all of
whom qualify as independent under the criteria set forth in Rule 10 A-3 of the Securities Exchange Act of 1934 and NYSE American Rule 803(b)(2)(c). The Board of Directors has determined that the Company’s directors, Matthew K. Behrent, Hughree F.
Brooks, and Richard M. Thon, are independent as defined by the NYSE American Rules, and that Matthew K. Behrent and Richard M. Thon are also independent as defined by Section 10A(m)(3) of the Securities Exchange Act of 1934 and the rules and
regulations of the Securities and Exchange Commission; and that none of these directors have any relationship which would interfere with the exercise of his independent judgment in carrying out his responsibilities as a director. Mr. Brooks did not
stand for reelection as a director at the annual meeting of shareholder of the Company held on December 12, 2017 and his term of office as a director ended at the conclusion of the meeting. In reaching its determination, the Board of Directors
reviewed certain categorical independence standards to provide assistance in the determination of director independence. The categorical standards are set forth below and provide that a director will not qualify as an independent director under the
NYSE American Rules if:
The Director is, or has been during the last three years, an employee or an officer of the Company or any of its affiliates;
The Director has received, or has an immediate family member 15 who has received, during any twelve consecutive months in the last three years any compensation from the Company in excess of $120,000, other than compensation for service on the Board of Directors, compensation to an immediate
family member who is an employee of the Company other than an executive officer, compensation received as an interim executive officer or benefits under a tax-qualified retirement plan, or non-discretionary compensation;
The Director is a member of the immediate family of an individual who is, or has been in any of the past three years, employed
by the Company or any of its affiliates as an executive officer;
The Director, or an immediate family member, is a partner in, or controlling shareholder or an executive officer of, any
for-profit business organization to which the Company made, or received, payments (other than those arising solely from investments in the Company’s securities) that exceed 5% of the Company’s or business organization’s consolidated gross revenues
for that year, or $200,000, whichever is more, in any of the past three years;
The Director, or an immediate family member, is employed as an executive officer of another entity where at any time during the
most recent three fiscal years any of the Company’s executives serve on that entity’s compensation committee; or
The Director, or an immediate family member, is a current partner of the Company’s outside auditors, or was a partner or
employee of the Company’s outside auditors who worked on the Company’s audit at any time during the past three years.
The following additional categorical standards were employed by the Board in determining whether a director qualified as
independent to serve on the Audit Committee and provide that a director will not qualify if:
| · |
The Director directly or indirectly accepts any consulting, advisory, or other compensatory fee from the Company or any of its subsidiaries; or
|
| · |
The Director is an affiliated person16 of the Company or any of its subsidiaries.
|
| · |
The Director participated in the preparation of the Company’s financial statements at any time during the past three years.
|
The independent members of the Board meet as often as necessary to fulfill their responsibilities, but meet at least annually in
executive session without the presence of non-independent directors and management.
| (15) |
Under these categorical standards “immediate family member” includes a person’s spouse, parents, children, siblings, mother-in-law, father-in-law, brother-in-law,
sister-in-law, son-in-law, daughter-in-law, and anyone who resides in such person’s home (other than a domestic employee).
|
| (16) |
For purposes of this categorical standard, an “affiliated person of the Company” means a person that directly or indirectly through intermediaries’ controls, or is
controlled by, or is under common control with the Company. A person will not be considered to be in control of the Company, and therefore not an affiliate of the Company, if he is not the beneficial owner, directly or indirectly of more
than 10% of any class of voting securities of the Company and he is not an executive officer of the Company. Executive officers of an affiliate of the Company as well as a director who is also an employee of an affiliate of the Company
will be deemed to be affiliates of the Company.
|
Audit and Non-Audit Fees
The following table presents the fees for professional audit services rendered by the Company’s independent registered public
accounting firm, for the audit of the Company’s annual consolidated financial statements and fees for professional audit services rendered for the quarterly reviews for the fiscal years ended December 31, 2018 and December 31, 2017. Hein &
Associates LLP (“Hein”) performed these services for the first three quarters of 2017. In November 2017, Hein combined with Moss Adams LLP (“Moss Adams”) and Moss Adams was selected by the Audit Committee to continue as the Company’s independent
accountants.
AUDIT AND NON-AUDIT FEES
|
2018
Moss Adams |
2017
Moss Adams |
2017
Hein |
||||||||||
|
Audit Fees
|
$
|
117,600
|
$
|
73,500
|
$
|
37,800
|
||||||
|
Audit-Related Fees
|
—
|
—
|
—
|
|||||||||
|
Tax Fees
|
—
|
—
|
—
|
|||||||||
|
All Other Fees
|
3,599
|
—
|
—
|
|||||||||
|
Total Fees
|
$
|
121,199
|
$
|
73,500
|
$
|
37,800
|
||||||
Audit fees include fees related to the services rendered in connection with the annual audit of the Company’s consolidated
financial statements, the quarterly reviews of the Company’s quarterly reports on Form 10-Q and the reviews of and other services related to statutory filings or engagements for the subject fiscal years.
Audit-related fees are for assurance and related services by the principal accountants that are reasonably related to the
performance of the audit or review of the Company’s financial statements.
Tax Fees include services for (i) tax compliance, (ii) tax advice, (iii) tax planning and (iv) tax reporting.
All Other Fees includes fees for all other services provided by the principal accountants not covered in the other categories
such as litigation support, etc.
All of the 2018 services described above were approved by the Audit Committee pursuant to the SEC rule that requires audit
committee pre-approval of audit and non-audit services provided by the Company’s independent auditors. The Audit Committee considered whether the provisions of such services, including non-audit services, by Moss Adams were compatible with
maintaining its independence and concluded they were.
PART IV.
|
A.
|
The following documents are filed as part of this Report:
|
| 1. |
Financial Statements:
|
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
| 2. |
Financial Schedules:
|
Schedules have been omitted because the information required to be set forth therein is not applicable or is included in the
Consolidated Financial Statements or notes thereto.
| 3. |
Exhibits.
|
The following exhibits are filed with, or incorporated by reference into this Report:
Exhibit Index
|
Exhibit Number
|
Description
|
|
Amended and Restated Certificate of Incorporation as of March 23,
2016 (Incorporated by reference to Exhibit 3 to registrant’s Report on Form 10-Q for the period ended September 30, 2016 filed November 14, 2016).
|
|
|
Amended and Restated Bylaws as of November 13, 2014 (Incorporated by reference to Exhibit 3.2 to the registrant’s Annual Report on Form 10-K for the year ended December 31, 2014 filed on March 30, 2015).
|
|
|
Agreement and Plan of Merger of Tengasco, Inc. (a Tennessee corporation with and into Tengasco, Inc., a Delaware corporation dated as of April 15, 2011 (Incorporated by reference to Exhibit 99.A to registrant’s
Definitive Proxy Statement pursuant to Schedule 14a filed May 2, 2011).
|
|
|
Tengasco, Inc. 2018 Incentive Stock Plan (Incorporated by reference to Appendix A to the Registrant’s Information Statement on Schedule 14C filed with the Securities and Exchange Commission on August 27, 2018)
|
|
|
Amended and Restated Loan Agreement between Tengasco, Inc. and
Prosperity Bank, effective March 16, 2017 (Incorporated by reference to Exhibit 10.14 to the registrant’s Annual Report on form 10-K for the year ended December
31, 2017 filed March 28, 2018).
|
|
|
Subscription Agreement of Hoactzin Partners, L.P. for the Company’s
ten well drilling program on its Kansas Properties dated August 3, 2007 (Incorporated by reference to Exhibit 10.15 to the registrant’s Annual Report on Form
10-K for the year ended December 31, 2007 filed March 31, 2008 [the “2007 Form 10-K”]).
|
|
|
Agreement and Conveyance of Net Profits Interest dated September 17,
2007 between Manufactured Methane Corporation as Grantor and Hoactzin Partners, LP as Grantee (Incorporated by reference to Exhibit 10.16 to the 2007 Form
10-K).
|
|
|
Agreement for Conditional Option for Exchange of Net Profits Interest
for Convertible Preferred Stock dated September 17, 2007 between Tengasco, Inc., as Grantor and Hoactzin Partners, L.P., as Grantee (Incorporated by reference
to Exhibit 10.17 to the 2007 Form 10-K).
|
|
|
Management Agreement dated December 18, 2007 between Tengasco, Inc.
and Hoactzin Partners, L.P. (Incorporated by reference to Exhibit 10.20 to the 2007 Form 10-K).
|
|
|
Code of Ethics (Incorporated by reference to Exhibit 14 to the registrant’s Annual Report on Form 10-K filed March 30, 2004).
|
|
Consent of LaRoche Petroleum Consultants, Ltd.
|
|
|
Certification pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
|
|
|
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
|
|
|
Report of LaRoche Petroleum Consultants, Ltd. has been added to the filing for the year ended December, 31, 2018
|
|
|
101.INS*
|
XBRL Instance Document
|
|
101.SCH*
|
XBRL Taxonomy Extension Schema Document
|
|
101.CAL*
|
XBRL Taxonomy Calculation Linkbase Document
|
|
101.DEF*
|
XBRL Taxonomy Definition Linkbase Document
|
|
101.LAB*
|
XBRL Taxonomy Label Linkbase Document
|
|
101.PRE*
|
XBRL Taxonomy Presentation Linkbase Document
|
* Exhibit filed with this Report
Pursuant to the requirements of Section 13 or 15 (d) of the Securities and Exchange Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
Dated: March 28, 2019
Tengasco, Inc.
(Registrant)
By: s/ Michael J. Rugen
Michael J. Rugen,
Chief Executive Officer
Principal Financial and Accounting Officer
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the
registrant and in their capacities and on the dates indicated.
|
Signature
|
Title
|
Date
|
|
s/ Matthew K. Behrent
|
Director
|
March 28, 2019
|
|
Matthew K. Behrent
|
||
|
s/ Peter E. Salas
|
Director
|
March 28, 2019
|
|
Peter E. Salas
|
||
|
s/ Richard M. Thon
|
Director
|
March 28, 2019
|
|
Richard M. Thon
|
||
|
s/ Michael J. Rugen
|
Chief Executive Officer and
|
March 28, 2019
|
|
Michael J. Rugen
|
Principal Financial Accounting Officer
|
Tengasco, Inc.
and Subsidiaries
|
Consolidated Financial Statements
Years Ended December 31, 2018, and 2017
|
|
Report of Independent Registered Public Accounting Firm
|
F-2
|
|
Consolidated Financial Statements
|
|
|
Consolidated Balance Sheets
|
F-3
|
|
Consolidated Statements of Operations
|
F-5
|
|
Consolidated Statements of Stockholders’ Equity
|
F-6
|
|
Consolidated Statements of Cash Flows
|
F-7
|
|
Notes to Consolidated Financial Statements
|
F-8
|
Report of Independent Registered Public Accounting Firm
To the Stockholders and the Board of Directors of
Tengasco, Inc.
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Tengasco and subsidiaries (the “Company”) as of December 31, 2018 and 2017, the
related consolidated statements of operations, stockholders’ equity, and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial
statements present fairly, in all material respects, the consolidated financial position of the Company as of December 31, 2018 and 2017, and the consolidated results of its operations and its cash flows for the years then ended, in conformity with
accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the
Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the Company in
accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain
reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over
financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial
reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error
or fraud, and performing procedures to respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the
accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable
basis for our opinion.
/s/ Moss Adams LLP
Denver, Colorado
March 28, 2019
We have served as the Company’s auditor since 2017.
Tengasco, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except per share and share data)
|
December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Assets
|
||||||||
|
Current
|
||||||||
|
Cash and cash equivalents
|
$
|
3,115
|
$
|
185
|
||||
|
Accounts receivable, less allowance for doubtful accounts of $0 and $14
|
533
|
517
|
||||||
|
Accounts receivable-related party, less allowance for doubtful accounts of $0 and $159
|
—
|
—
|
||||||
|
Inventory
|
464
|
541
|
||||||
|
Prepaid expenses
|
235
|
130
|
||||||
|
Discontinued operations included in current assets
|
—
|
121
|
||||||
|
Total current assets
|
4,347
|
1,494
|
||||||
|
Loan fees, net
|
9
|
13
|
||||||
|
Oil and gas properties, net (full cost accounting method)
|
4,804
|
4,720
|
||||||
|
Other property and equipment, net
|
190
|
135
|
||||||
|
Accounts receivable - noncurrent
|
130
|
242
|
||||||
|
Other noncurrent assets
|
4
|
4
|
||||||
|
Discontinued operations included in non-current assets
|
—
|
1,497
|
||||||
|
Total assets
|
$
|
9,484
|
$
|
8,105
|
||||
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Balance Sheets
(In thousands, except per share and share data)
|
December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Liabilities and Stockholders’ Equity
|
||||||||
|
Current liabilities
|
||||||||
|
Accounts payable – trade
|
$
|
132
|
$
|
181
|
||||
|
Accounts payable – other
|
—
|
159
|
||||||
|
Accrued liabilities
|
282
|
187
|
||||||
|
Current maturities of long-term debt
|
51
|
41
|
||||||
|
Asset retirement obligation - current
|
83
|
—
|
||||||
|
Discontinued operations included in current liabilities
|
—
|
43
|
||||||
|
Total current liabilities
|
548
|
611
|
||||||
|
Asset retirement obligation - non current
|
2,096
|
2,270
|
||||||
|
Long term debt, less current maturities
|
73
|
49
|
||||||
|
Total liabilities
|
2,717
|
2,930
|
||||||
|
Commitments and contingencies (Note 9)
|
||||||||
|
Stockholders’ equity
|
||||||||
|
Preferred stock, 25,000,000 shares authorized:
|
||||||||
|
Series A Preferred stock, $0.0001 par value, 10,000 shares designated; 0 shares issued and
outstanding
|
—
|
—
|
||||||
|
Common stock, $.001 par value: authorized 100,000,000 Shares; 10,639,290 and 10,619,924 shares
issued and outstanding
|
11
|
11
|
||||||
|
Additional paid in capital
|
58,276
|
58,253
|
||||||
|
Accumulated deficit
|
(51,520
|
)
|
(53,089
|
)
|
||||
|
Total stockholders’ equity
|
6,767
|
5,175
|
||||||
|
Total liabilities and stockholders’ equity
|
$
|
9,484
|
$
|
8,105
|
||||
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Statements of Operations
(In thousands, except per share and share data)
|
Year ended December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Revenues
|
||||||||
|
Oil and gas properties
|
$
|
5,871
|
$
|
4,683
|
||||
|
Total revenues
|
5,871
|
4,683
|
||||||
|
Cost and expenses
|
||||||||
|
Production costs and taxes
|
3,591
|
3,444
|
||||||
|
Depreciation, depletion, and amortization
|
795
|
862
|
||||||
|
General and administrative
|
1,245
|
1,171
|
||||||
|
Total cost and expenses
|
5,631
|
5,477
|
||||||
|
Net income (loss) from operations
|
240
|
(794
|
)
|
|||||
|
Other income (expense)
|
||||||||
|
Net interest expense
|
(5
|
)
|
(53
|
)
|
||||
|
Gain on sale of assets
|
33
|
2
|
||||||
|
Other income
|
157
|
—
|
||||||
|
Total other income (expense)
|
185
|
(51
|
)
|
|||||
|
Income (loss) from operations before income tax
|
425
|
(845
|
)
|
|||||
|
Deferred income tax benefit
|
17
|
242
|
||||||
|
Net income (loss) from continuing operations
|
442
|
(603
|
)
|
|||||
|
Net income from discontinued operations
|
1,127
|
29
|
||||||
|
Net income (loss)
|
$
|
1,569
|
$
|
(574
|
)
|
|||
|
Net income (loss) per share - basic and fully diluted
|
||||||||
|
Continuing operations
|
$
|
0.04
|
$
|
(0.06
|
)
|
|||
|
Discontinued operations
|
$
|
0.11
|
$
|
—
|
||||
|
Shares used in computing earnings per share
|
||||||||
|
Basic and fully diluted
|
10,628,170
|
10,081,218
|
||||||
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity
(In thousands, except per share and share data)
|
Common Stock
|
Paid-in
|
Accumulated
|
||||||||||||||||||
|
Shares
|
Amount
|
Capital
|
Deficit
|
Total
|
||||||||||||||||
|
Balance, December 31, 2016
|
6,097,723
|
$
|
6
|
$
|
55,787
|
$
|
(52,515
|
)
|
$
|
3,278
|
||||||||||
|
Net loss
|
—
|
—
|
—
|
(574
|
)
|
(574
|
)
|
|||||||||||||
|
Compensation expense related to stock issued
|
23,503
|
—
|
14
|
—
|
14
|
|||||||||||||||
|
Shares issued for rights offering
|
4,498,698
|
5
|
2,452
|
—
|
2,457
|
|||||||||||||||
|
Balance, December 31, 2017
|
10,619,924
|
$
|
11
|
$
|
58,253
|
$
|
(53,089
|
)
|
$
|
5,175
|
||||||||||
|
Net income
|
—
|
—
|
—
|
1,569
|
1,569
|
|||||||||||||||
|
Compensation expense related to stock issued
|
19,366
|
—
|
23
|
—
|
23
|
|||||||||||||||
|
Balance, December 31, 2018
|
10,639,290
|
$
|
11
|
$
|
58,276
|
$
|
(51,520
|
)
|
$
|
6,767
|
||||||||||
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
(In thousands)
|
Year Ended December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Operating activities
|
||||||||
|
Net income (loss) from continuing operations
|
$
|
442
|
$
|
(603
|
)
|
|||
|
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities
|
||||||||
|
Depreciation, depletion, and amortization
|
795
|
862
|
||||||
|
Amortization of loan fees-interest expenses
|
4
|
20
|
||||||
|
Accretion of discount on asset retirement obligation
|
141
|
141
|
||||||
|
(Gain) loss on asset sales
|
(33
|
)
|
(2
|
)
|
||||
|
Compensation and services paid in stock / stock options
|
23
|
14
|
||||||
|
Changes in assets and liabilities:
|
||||||||
|
Accounts receivable
|
96
|
(318
|
)
|
|||||
|
Inventory, prepaid expense, and other assets
|
(28
|
)
|
203
|
|||||
|
Accounts payable
|
(58
|
)
|
(78
|
)
|
||||
|
Accrued liabilities
|
(64
|
)
|
(73
|
)
|
||||
|
Settlement on asset retirement obligations
|
(25
|
)
|
(53
|
)
|
||||
|
Net cash provided by operating activities - continuing operations
|
1,293
|
113
|
||||||
|
Net cash provided by operating activities - discontinued operations
|
44
|
41
|
||||||
|
Net cash provided by operating activities
|
1,337
|
154
|
||||||
|
Investing activities
|
||||||||
|
Additions to oil and gas properties
|
(1,011
|
)
|
(169
|
)
|
||||
|
Proceeds from sale of oil and gas properties
|
7
|
7
|
||||||
|
Additions to other property & equipment
|
(27
|
)
|
(17
|
)
|
||||
|
Proceeds from sale of other property & equipment
|
8
|
—
|
||||||
|
Net cash used in investing activities - continuing operations
|
(1,023
|
)
|
(179
|
)
|
||||
|
Net cash provided by investing activities - discontinued operations
|
2,658
|
—
|
||||||
|
Net cash provided by (used in) investing activities
|
1,635
|
(179
|
)
|
|||||
|
Financing activities
|
||||||||
|
Proceeds from stock issuance in rights offering
|
—
|
2,699
|
||||||
|
Cost of stock issuance in rights offering
|
—
|
(102
|
)
|
|||||
|
Proceeds from borrowings
|
100
|
400
|
||||||
|
Repayment of borrowings
|
(142
|
)
|
(2,854
|
)
|
||||
|
Loan fees
|
—
|
(9
|
)
|
|||||
|
Net cash provided by (used in) financing activities - continuing operations
|
(42
|
)
|
134
|
|||||
|
Net cash provided by (used in) financing activities - discontinued operations
|
—
|
—
|
||||||
|
Net cash provided by (used in) financing activities
|
(42
|
)
|
134
|
|||||
|
Net change in cash and cash equivalents
|
2,930
|
109
|
||||||
|
Cash and cash equivalents, beginning of period
|
185
|
76
|
||||||
|
Cash and cash equivalents, end of period
|
$
|
3,115
|
$
|
185
|
||||
|
Supplemental cash flow information:
|
||||||||
|
Cash interest payments
|
$
|
—
|
$
|
33
|
||||
|
Supplemental non-cash investing and financing activities:
|
||||||||
|
Financed company vehicles
|
$
|
136
|
$
|
81
|
||||
|
Cost of stock issuance in rights offering
|
$
|
—
|
$
|
(140
|
)
|
|||
|
Asset retirement obligations incurred
|
$
|
7
|
$
|
1
|
||||
|
Revisions to asset retirement obligations
|
$
|
(198
|
)
|
$
|
138
|
|||
|
Capital expenditures included in accounts payable and accrued liabilities
|
$
|
9
|
$
|
—
|
||||
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
1. Description of Business and Significant Accounting Policies
Tengasco, Inc. (the “Company”) is a Delaware corporation. The Company is in the business of exploration for and production of
oil and natural gas. The Company’s primary area of exploration and production is in Kansas.
The Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owned and operated a pipeline which it constructed
to transport natural gas from the Company’s Swan Creek Field to customers in Kingsport, Tennessee. The Company sold all its pipeline assets on August 16, 2013.
The Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) operated treatment and delivery facilities in
Church Hill, Tennessee for the extraction of methane gas from a landfill for eventual sale as natural gas and for the generation of electricity. The Company sold all its methane facility assets on January 26, 2018. (See Note 5. Discontinued
Operations)
Principles of Consolidation
The accompanying consolidated financial statements are presented in accordance with accounting principles generally accepted in
the United States (“U.S. GAAP”). The consolidated financial statements include the accounts of the Company, and its wholly-owned subsidiaries after elimination of all significant intercompany transactions and balances.
Use of Estimates
The accompanying consolidated financial statements are prepared in conformity with U.S. GAAP which require management to make
estimates and assumptions that affect the reported amounts of assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include reserve
quantities and estimated future cash flows associated with proved reserves, which significantly impact depletion expense and potential impairments of oil and natural gas properties, income taxes and the valuation of deferred tax assets, stock-based
compensation and commitments and contingencies. We analyze our estimates based on historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the
consolidated financial statements are appropriate, actual results could differ from those estimates.
Revenue Recognition
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. (See Note 5. Discontinued Operations)
The Company operates certain salt water disposal wells, some of which accept water from third parties. The contracts with the
third parties primarily require a flat monthly fee for the third parties to dispose water into the wells. In some cases, the contract is based on a per barrel charge to dispose water into the wells. There is no requirement under the contracts for
these third parties to use these wells for their water disposal. If the third parties do dispose water into the Company operated wells in a given month, the Company has met its contractual obligations and revenues are recognized for that month.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The following table presents the disaggregated revenue by commodity for the years ended December 31, 2018 and 2017 (in
thousands):
|
Year Ended
|
Year Ended
|
|||||||
|
December 31, 2018
|
December 31, 2017
|
|||||||
|
Revenue (in thousands):
|
||||||||
|
Crude oil
|
$
|
5,840
|
$
|
4,653
|
||||
|
Salt water disposal fees
|
31
|
30
|
||||||
|
Total
|
$
|
5,871
|
$
|
4,683
|
||||
There were no natural gas imbalances at December 31, 2018 or December 31, 2017.
Cash and Cash Equivalents
Cash and cash equivalents include temporary cash investments with a maturity of ninety days or less at date of purchase.
Inventory
Inventory consists of crude oil in tanks and is carried at lower of cost or market value. The cost component of the oil
inventory is calculated using the average quarterly per barrel cost for the quarter ended December 31, 2018 and December 31, 2017. During 2018, the Company included production costs and taxes in its calculation of estimated cost. During 2017, the
Company included production costs and taxes, allocated general and administrative costs, depletion, and allocated interest in its calculation of estimated cost. The Company made this change as it believes that excluding allocated general and
administrative costs, depletion, and interests provides a better estimate of its cost of oil inventory. The market component is calculated using the average December 2018 and December 2017 oil sales price for the Company’s Kansas properties. In
addition, the Company also carried equipment and materials to be used in its Kansas operation and is carried at the lower of cost or market value. The cost component of the equipment and materials inventory represents the original cost paid for the
equipment and materials. The market component is based on estimated sales value for similar equipment and materials at the end of each year. At December 31, 2018 and December 31, 2017, inventory consisted of the following (in thousands):
|
December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Oil – carried at cost
|
$
|
359
|
$
|
436
|
||||
|
Equipment and materials – carried at market
|
105
|
105
|
||||||
|
Total inventory
|
$
|
464
|
$
|
541
|
||||
Oil and Gas Properties
The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development
activities. Under this method, all costs incurred in connection with acquisition, exploration, and development of oil and gas reserves are capitalized. Capitalized costs include lease acquisitions, seismic related costs, certain internal
exploration costs, drilling, completion, and estimated asset retirement costs. The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated asset retirement costs which are not
already included net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The Company has determined its reserves based upon reserve reports provided by LaRoche Petroleum Consultants Ltd. since
2009. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred. The Company had $23,000 and $0 in unevaluated properties as of December 31,
2018 and 2017, respectively. 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.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
At the end of each reporting period, the Company performs a “ceiling test” on the value of the net capitalized cost of oil and
gas properties. This test compares the net capitalized cost (capitalized cost of oil and gas properties, net of accumulated depreciation, depletion and amortization and related deferred income taxes) to the present value of estimated future net
revenues from oil and gas properties using an average price (arithmetic average of the beginning of month prices for the prior 12 months) and current cost discounted at 10% plus cost of properties not being amortized and the lower of cost or
estimated fair value of unproven properties included in the cost being amortized (ceiling). If the net capitalized cost is greater than the ceiling, a write-down or impairment is required. A write-down of the carrying value of the asset is a
non-cash charge that reduces earnings in the current period. Once incurred, a write-down may not be reversed in a later period. The Company performed its ceiling tests during 2017 and 2018, resulting in no impairments of its oil and gas properties.
Asset Retirement Obligation
An asset retirement obligation associated with the retirement of a tangible long-lived asset is recognized as a liability in the
period incurred, with an associated increase in the carrying amount of the related long-lived asset, our oil and natural gas properties. The cost of the tangible asset, including the asset retirement cost, is depleted over the useful life of the
asset. The asset retirement obligation is recorded at its estimated fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at our credit-adjusted risk-free interest rate.
Accretion expense is recognized over time as the discounted liability is accreted to its expected settlement value. Accretion expense is recorded as “Production costs and taxes” in the Consolidated Statements of Operations. If the estimated future
cost of the asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions to estimated asset retirement obligations can result from changes in retirement cost estimates,
revisions to estimated inflation rates, and changes in the estimated timing of abandonment.
Manufactured Methane Facilities
The Manufactured Methane facilities were placed into service in April 2009 and were being depreciated using the straight-line
method over the useful life based on the estimated landfill closure date of December 2041. The Company sold all its methane facility assets, except the applicable U.S. patent, on January 26, 2018. (See Note 5. Discontinued Operations)
Other Property and Equipment
Other property and equipment is carried at cost. The Company provides for depreciation of other property and equipment using
the straight-line method over the estimated useful lives of the assets which range from two to seven years. Net gains or losses on other property and equipment disposed of are included in operating income in the period in which the transaction
occurs.
Stock-Based Compensation
The Company records stock-based compensation to employees based on the estimated fair value of the award at grant date. We
recognize expense on a straight line basis over the requisite service period. For stock-based compensation that vests immediately, the Company recognizes the entire expense in the quarter in which the stock-based compensation is granted. The Company
recorded compensation expense of $23,000 in 2018 and $14,000 in 2017.
Accounts Receivable
Accounts receivable consist of uncollateralized joint interest owner obligations due within 30 days of the invoice date,
uncollateralized accrued revenues due under normal trade terms, generally requiring payment within 30 days of production, and other miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are
applied to the earliest unpaid items. We review accounts receivable periodically and reduce the carrying amount by a valuation allowance that reflects our best estimate of the amount that may not be collectible. An allowance was recorded at December
31, 2018 and 2017. At December 31, 2018 and 2017, accounts receivable consisted of the following (in thousands):
|
December 31,
|
||||||
|
2018
|
2017
|
|||||
|
Revenue
|
$
|
396
|
$
|
479
|
||
|
Tax
|
129
|
—
|
||||
|
Joint interest
|
8
|
23
|
||||
|
Other
|
—
|
29
|
||||
|
Allowance for doubtful accounts
|
—
|
(14)
|
||||
|
Total accounts receivable
|
$
|
533
|
$
|
517
|
||
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
At year-end 2018, the Company removed the $159,000 from Accounts receivable-related party and also from the associated allowance
for doubtful accounts. This removal occurred as the Company determined that the outstanding balance of the associated payable recorded in Accounts payable – other was not recoverable against the Company by operation of applicable statutes of
limitation or prescription.
At December 31, 2018 and December 31, 2017, the Company recorded a tax related non-current receivable in the amount of $130,000
and $242,000, respectively. At September 30, 2018, based upon its expected recovery, the Company reclassified $121,000 of this tax related non-current receivable as a current receivable. At December 31, 2018, the increased the tax related current
and non-current receivable by approximately $8,000 and $9,000, respectively. (See Note 13. Income Taxes)
Income Taxes
Income taxes are reported in accordance with U.S. GAAP, which requires the establishment of deferred tax accounts for all
temporary differences between the financial reporting and tax bases of assets and liabilities, using currently enacted federal and state income tax rates. In addition, deferred tax accounts must be adjusted to reflect new rates if enacted into law.
Realization of deferred tax assets is contingent on the generation of future taxable income. As a result, management considers
whether it is more likely than not that all or a portion of such assets will be realized during periods when they are available, and if not, management provides a valuation allowance for amounts not likely to be recognized.
Management periodically evaluates tax reporting methods to determine if any uncertain tax positions exist that would require the
establishment of a loss contingency. A loss contingency would be recognized if it were probable that a liability has been incurred as of the date of the financial statements and the amount of the loss can be reasonably estimated.
The amount recognized is subject to estimates and management’s judgment with respect to the likely outcome of each uncertain tax
position. The amount that is ultimately incurred for an individual uncertain tax position or for all uncertain tax positions in the aggregate could differ from the amount recognized.
Concentration of Credit Risk
Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and
accounts receivable. Cash and cash equivalents are maintained at financial institutions and, at times, balances may exceed federally insured limits. The Company has never experienced any losses related to these balances.
The Company’s primary business activities include oil sales to a limited number of customers in the state of Kansas. The
related trade receivables subject the Company to a concentration of credit risk. The Company sells a majority of its crude oil primarily to two customers in Kansas. Although management believes that customers could be replaced in the ordinary
course of business, if the present customers were to discontinue business with the Company, it may have a significant adverse effect on the Company’s results of operations.
Revenue from the top two purchasers accounted for 85.6% and 13.8% of total revenues for year ended December 31, 2018. Revenue
from the top two purchasers accounted for 84.6% and 14.8% of total revenues for year ended December 31, 2017. As of December 31, 2018 and 2017, two of the Company’s oil purchasers accounted for 93.2% and 89.7%, respectively of accounts receivable,
of which one oil purchaser accounted for 84.4% and 74.4%, respectively.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The amounts above exclude revenues and accounts receivable associated with Discontinued Operations. (see Note 5. Discontinued Operations)
Earnings per Common Share
The Company reports basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted
earnings per common share which include the effect of all potentially dilutive securities unless their impact is anti-dilutive. The following are reconciliations of the numerators and denominators of the Company’s basic and diluted earnings per
share, (in thousands except for share and per share amounts):
|
For the years ended December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Income (numerator):
|
||||||||
|
Net income (loss) from continuing operations
|
$
|
442
|
$
|
(603
|
)
|
|||
|
Net income from discontinued operations
|
1,127
|
29
|
||||||
|
Weighted average shares (denominator):
|
||||||||
|
Weighted average shares - basic
|
10,628,170
|
10,081,218
|
||||||
|
Dilution effect of share-based compensation, treasury method
|
—
|
—
|
||||||
|
Weighted average shares - dilutive
|
10,628,170
|
10,081,218
|
||||||
|
Income (loss) per share – Basic and Dilutive:
|
||||||||
|
Continuing operations
|
$
|
0.04
|
$
|
(0.06
|
)
|
|||
|
Discontinued operations
|
$
|
0.11
|
$
|
—
|
||||
Options issued to the Company’s directors in which the exercise price was higher than the average market price each quarter was also excluded from
diluted shares as they would have been anti-dilutive (See Note 12. Stock and Stock Options). In addition, the shares that would be issued to employees and Company directors have also been excluded from this calculation. (See Note 9. Commitments and
Contingencies)
Fair Value of Financial Instruments
The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, accounts payables,
accrued liabilities and long term debt approximates fair value as of December 31, 2018 and 2017.
Derivative Financial Instruments
The Company uses derivative instruments to manage our exposure to commodity price risk on sales of oil production. The Company
does not enter into derivative instruments for speculative trading purposes. The Company presents the fair value of derivative contracts on a net basis where the right to offset is provided for in our counterparty agreements. As of December 31,
2018 and 2017, the Company did not have any open derivatives.
Reclassifications
Certain prior year amounts have been reclassified to conform to current year presentation with no effect on net income.
2. Recent Accounting Pronouncements
In February 2016, the FASB issued Update 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 in this Update is 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. Upon adoption on January 1,
2019, the Company anticipates that it will record right-of-use assets and liabilities associated with operating leases of approximately $100,000.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
On September 17, 2007, Hoactzin Partners, L.P.
(“Hoactzin”) subscribed to a drilling program offered by the Company 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. Hoactzin was also conveyed a net profits interest in the MMC facility at the Carter Valley municipal solid waste landfill owned and operated by Republic
Services, Inc. in Church Hill, Tennessee where the Company installed a propriety combination of advanced gas treatment technology to extract the methane component of the purchased gas stream (the “Methane Project”). The net profits interest owned
by Hoactzin during 2017 was 7.5% of the net profits as defined by agreement and takes into account specific costs and expenses as well as gross gas revenues for the project. As a result of the startup costs, monthly operating expenses, and gas
production levels experienced, no net profits as defined were realized during the period from the project startup in April, 2009 through January 26, 2018, the date the Company sold the Methane Project to a third party, for payment to Hoactzin under
the net profits interest. In addition, during Company during the 4th quarter of 2018, the Company acquired all of Hoactzin’s interest in the drilling program
wells for $134,690.
On December 18, 2007, the Company entered into a Management Agreement with Hoactzin to manage on behalf of Hoactzin all of its
working interest in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As part of the consideration for the Company’s agreement to enter into the Management
Agreement, Hoactzin granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or workover activities undertaken on Hoactzin’s managed properties during the term of the
Management Agreement. The Management Agreement expired on December 18, 2012.
The Company entered into a transition agreement with Hoactzin whereby the Company no longer performs operations, but
administratively assists Hoactzin in becoming operator of record of these wells and transferring all bonds from the Company to Hoactzin. This assistance is primarily related to signing the necessary documents to effectuate this transition. Hoactzin
and its controlling member are indemnifying the Company for any costs or liabilities incurred by the Company resulting from such assistance, or the fact that the Company is the operator of record on certain of these wells. As of the date of this
Report, the Company continues to administratively assist Hoactzin with this transition process.
As operator during the term of the Management Agreement that expired in 2012, the Company routinely contracted in its name for
goods and services with vendors in connection with its operation of the Hoactzin properties. In practice, Hoactzin directly paid these invoices for goods and services that were contracted in the Company’s name. As a result of the operations
performed by Hoactzin in late 2009 and 2010, Hoactzin had significant past due balances to several vendors, a portion of which were included on the Company’s balance sheet. Payables related to these past due and ongoing operations remained
outstanding at December 31, 2017 in the amount of $159,000. The Company has recorded the Hoactzin-related payables and the corresponding receivable from Hoactzin as of December 31, 2017 in its Consolidated Balance Sheets under “Accounts payable –
other” and “Accounts receivable – related party”. However, Hoactzin had not made payments to reduce the $159,000 of past due balances from 2009 and 2010 since the second quarter of 2012. Based on these circumstances, the Company has elected to
establish an allowance in the amount of $159,000 for the balances outstanding at December 31, 2017. This allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party”. The resulting balances
recorded in the Company’s Consolidated Balance Sheets under “Accounts receivable – related party, less allowance for doubtful accounts of $159” are $0 at December 31, 2017. At year-end 2018, the Company has determined that the outstanding balances
under these vendor contracts for services or materials provided in 2009 and 2010 are not recoverable against the Company by operation of applicable statutes of limitation or prescription, and consequently, these amounts have been removed from the
Company’s balance sheet at December 31, 2018. This removal also resulted in the Company recording other income in 2018 in the amount of $159,000.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The following table sets forth information concerning the Company’s oil and gas properties: (in thousands):
|
December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Oil and gas properties
|
$
|
6,503
|
$
|
5,704
|
||||
|
Unevaluated properties
|
23
|
—
|
||||||
|
Accumulated depreciation, depletion and amortization
|
(1,722
|
)
|
(984
|
)
|
||||
|
Oil and gas properties, net
|
$
|
4,804
|
$
|
4,720
|
||||
During the years ended December 31, 2018 and 2017, the Company recorded depletion expense of $722,000 and $796,000,
respectively.
5. Discontinued Operations
The following table sets forth information concerning Discontinued Operations: (in thousands):
|
December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Accounts receivable
|
$
|
—
|
$
|
91
|
||||
|
Other current assets
|
—
|
30
|
||||||
|
Discontinued operations included in current assets
|
$
|
—
|
$
|
121
|
||||
|
Property, plant, and equipment
|
$
|
—
|
$
|
1,681
|
||||
|
Accumulated depreciation, depletion, and amortization
|
—
|
(184
|
)
|
|||||
|
Discontinued operations included in non-current assets
|
$
|
—
|
$
|
1,497
|
||||
|
Accounts payable - trade
|
$
|
—
|
$
|
27
|
||||
|
Accrued and other current liabilities
|
—
|
16
|
||||||
|
Discontinued operations included in current liabilities
|
$
|
—
|
$
|
43
|
||||
|
For the years ended December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Revenues
|
$
|
6
|
$
|
580
|
||||
|
Production costs and taxes
|
(40
|
)
|
(489
|
)
|
||||
|
Depreciation, depletion, and amortization
|
(4
|
)
|
(62
|
)
|
||||
|
Interest income
|
—
|
—
|
||||||
|
Gain on sale of assets
|
1,165
|
—
|
||||||
|
Deferred income tax benefit
|
—
|
—
|
||||||
|
Net income (loss) from discontinued operations
|
$
|
1,127
|
$
|
29
|
||||
The Discontinued Operations are related to the Manufactured Methane facilities. The Company sold all its methane facility assets,
except the applicable U.S. patent, on January 26, 2018 for $2.65 million
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Other property and equipment consisted of the following as of December 31, 2018: (in thousands)
|
Type
|
Depreciable
Life |
Gross Cost
|
Accumulated
Depreciation |
Net Book
Value |
|||||||||||
|
Machinery and equipment
|
5-7 yrs
|
$
|
20
|
$
|
20
|
$
|
—
|
||||||||
|
Vehicles
|
2-5 yrs
|
293
|
103
|
190
|
|||||||||||
|
Other
|
5 yrs
|
63
|
63
|
—
|
|||||||||||
|
Total
|
$
|
376
|
$
|
186
|
$
|
190
|
|||||||||
Other property and equipment consisted of the following as of December 31, 2017: (in thousands)
|
Type
|
Depreciable
Life |
Gross Cost
|
Accumulated
Depreciation |
Net Book
Value |
|||||||||||
|
Machinery and equipment
|
5-7 yrs
|
$
|
20
|
$
|
20
|
$
|
—
|
||||||||
|
Vehicles
|
2-5 yrs
|
318
|
183
|
135
|
|||||||||||
|
Other
|
5 yrs
|
63
|
63
|
—
|
|||||||||||
|
Total
|
$
|
401
|
$
|
266
|
$
|
135
|
|||||||||
The Company uses the straight-line method of depreciation for other property and equipment. During each of the years ended
December 31, 2018 and 2017, the Company recorded depreciation expense of $73,000 and $66,000, respectively.
7. Long-Term Debt
Long-term debt consisted of the following: (in thousands)
|
December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Note payable to a bank, with interest only payment until maturity.
|
$
|
—
|
$
|
—
|
||||
|
Installment notes bearing interest at the rate of 5.0% to 6.5% per annum collateralized by vehicles
with monthly payments including interest, insurance and maintenance of approximately $10
|
124
|
90
|
||||||
|
Total long-term debt
|
124
|
90
|
||||||
|
Less current maturities
|
(51
|
)
|
(41
|
)
|
||||
|
Long-term debt, less current maturities
|
$
|
73
|
$
|
49
|
||||
Future debt payments to unrelated entities as of December 31, 2018 consisted of the following: (in thousands)
|
2019
|
2020
|
2021
|
Total
|
|||||||||||||
|
Bank Credit Facility
|
$
|
—
|
$
|
—
|
$
|
—
|
$
|
—
|
||||||||
|
Company Vehicles
|
$
|
51
|
$
|
47
|
$
|
26
|
$
|
124
|
||||||||
|
Total
|
$
|
51
|
$
|
47
|
$
|
26
|
$
|
124
|
||||||||
At December 31, 2018, 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, 2018, the Company’s borrowing base was $3 million, subject to a credit limit based on current covenants of approximately $2.74 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, 2018, 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, 2018, the interest rate on this credit facility was 6.00%. The Company was in compliance with all covenants during the quarter ended
December 31, 2018.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
On August 24, 2018, 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 increase the borrowing base to $3 million, subject to a credit limit based on current covenants of approximately $2.74 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 5.50% at the date of the amendment. The maximum line of credit of the Company under the Prosperity Bank credit facility
remained $50 million and the Company had no outstanding borrowing under the facility as of December 31, 2018. The next borrowing base review will take place in April 2019.
On March 21, 2018, the Company’s senior credit facility with Prosperity Bank after Prosperity Bank’s review of the Company’s
owned producing properties was amended to increase the borrowing base to $2 million and the maturity date was extended to July 31, 2020. The borrowing base remained subject to the existing periodic redetermination provisions in the credit facility.
The interest rate remained prime plus 0.50% per annum. This rate was 5.00% 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, 2018 and December 31, 2017. The next borrowing base review
will take place in April 2019.
8. Liquidity
The Company incurred a net loss of approximately $574,000 in 2017 and $4.2 million in 2016. In January 2018, the Company sold its
methane facility for $2.65 million. During 2019, the Company believes its revenues as well as the proceeds received from the sale of the methane facility will be sufficient to fund operating and general and administrative expenses and to remain in
compliance with its bank covenants. If revenues and the proceeds from the sale of the methane facility are not sufficient to fund these expenses or if the Company needs additional funds for capital spending, the Company could borrow funds against
the credit facility as this facility currently has $2.74 million credit limit base with no funds currently drawn. In addition, if required, the Company could also issue additional shares of stock and/or sell assets as needed to further fund
operations.
9. Commitments and Contingencies
The Company as designated operator of the Hoactzin properties was administratively issued an “Incident of Non-Compliance” by the
Bureau of Safety and Environmental Enforcement (“BSEE”) during the quarter ended September 30, 2012 concerning one of Hoactzin’s operated properties. This action called for payment of a civil penalty of $386,000 for failure to provide, upon request,
documentation to the BSEE evidencing that certain safety inspections and tests had been conducted in 2011. On July 14, 2015, the federal district court in the Eastern District of Louisiana affirmed the civil penalty without reduction. The Company
did not further appeal. In the third quarter of 2015, the Company paid the civil penalty and statutory interest thereon from funds borrowed under its credit facility. In the fourth quarter of 2015, the Company received a return of the cash
collateral previously provided to RLI Insurance Company. The Company has not advanced any funds to pay any obligations of Hoactzin and no borrowing capability of the Company has been used in connection with its obligations under the Management
Agreement, except for those funds used to pay the civil penalty and interest thereon.
During the second quarter of 2015, the Company received from Hoactzin a copy of an internal analysis prepared by Hoactzin
setting out certain issues that Hoactzin may consider to form the basis of operational and other claims against the Company primarily under the Management Agreement. This analysis raised issues other than the “Incident of Non-Compliance” discussed
above. The Company is discussing this analysis, as well as the civil penalty discussed above, with Hoactzin in an effort to determine whether there is possibility of a reasonable resolution of some or all of these matters on a negotiated basis.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Cost Reduction Measures
Commencing in the quarter ended March 31, 2015 and continuing into the quarter ended June 30, 2018, the Company implemented cost
reduction measures including compensation reductions for each employee as well as members of the Board of Directors. These compensation reductions were to remain in place until such time, if any, that the market price of crude oil, calculated as a
thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $70 per barrel. In May 2018, oil prices as so calculated exceeded $70 and compensation reverted to the levels in place before the
reductions became effective. At such time, if any, that the market price of crude oil, calculated as a thirty day trailing average of WTI postings as published by the U.S. Energy Information Administration meets or exceeds $85 per barrel, all
previous reductions made will be reimbursed, a portion which may be paid in stock, to each employee and members of the Board of Directors if is still employed by the Company or still a member of the Board of Directors. For the period January 1, 2015
through December 31, 2018, the reductions were approximately $424,000. Of the $424,000, approximately $95,000 will be paid in the Company’s common stock. The $95,000 value represents approximately 100,000 common share valued at $0.95 per share
which represents the closing price on December 31, 2018. The Company has not accrued any liabilities associated with these compensation reductions.
Legal Proceedings
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.
10. Fair Value Measurements
FASB ASC 820, “Fair Value Measurements and Disclosures”, establishes a framework for measuring fair value. That framework
provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets and liabilities (Level 1
measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy under FASB ASC 820 are described as follows:
Level 1 – Observable inputs, such as unadjusted quoted prices in active markets, for substantially identical assets and liabilities.
Level 2 – Observable inputs other than quoted prices within Level 1 for similar assets and liabilities. These include quoted prices for similar
assets and liabilities in active markets, quoted prices for identical assets and liabilities in markets that are not active, or other inputs that are observable or can be corroborated by observable market data. If the asset or liability has a
specified or contractual term, the input must be observable for substantially the full term of the asset or liability.
Level 3 – Unobservable inputs that are supported by little or no market activity, generally requiring a significant amount of judgment by
management. The assets or liabilities fair value measurement level within the fair value hierarchy is based on the lowest level of any input that is significant to the fair value measurement. Valuation techniques used need to maximize the use of
observable inputs and minimize the use of unobservable inputs.
The methods described above may produce a fair value calculation that may not be indicative of net realizable value or
reflective of future fair values. Further, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain
financial instruments could result in a different fair value measurement at the reporting date.
Upon completion of wells, the Company records an asset retirement obligation at fair value using Level 3 assumptions.
Nonfinancial assets and liabilities are measured at fair value on a nonrecurring basis upon impairment. The carrying amounts of
other financial instruments including cash and cash equivalents, accounts receivable, account payables, accrued liabilities and long term debt in our balance sheet approximates fair value as of December 31, 2018 and December 31, 2017.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon and
remediate our producing properties at the end of their productive lives in accordance with applicable laws. The following table summarizes the Company’s Asset Retirement Obligation transactions for the years ended December 31, 2017 and 2018 (in
thousands):
|
Balance December 31, 2016
|
$
|
2,046
|
||
|
Accretion expense
|
141
|
|||
|
Liabilities incurred
|
1
|
|||
|
Liabilities settled
|
(45
|
)
|
||
|
Liabilities sold properties
|
(11
|
)
|
||
|
Revisions in estimated liabilities
|
138
|
|||
|
Balance December 31, 2017
|
$
|
2,270
|
||
|
Accretion expense
|
141
|
|||
|
Liabilities incurred
|
7
|
|||
|
Liabilities settled
|
(41
|
)
|
||
|
Revisions in estimated liabilities
|
(198
|
)
|
||
|
Balance December 31, 2018
|
$
|
2,179
|
The revisions in estimated liabilities resulted from change in timing of wells to be plugged, change in inflation factor, and
change in current plugging costs.
12. Stock and Stock Options
In October 2000, the Company approved a Stock Incentive Plan which was effective for a ten-year period commencing on October 25,
2000 and ending on October 24, 2010. The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to participants under the original Plan was not to exceed 7,000,000. An amendment to the Plan
increasing the number of shares that may be issued under the Plan by 3,500,000 shares and extending the Plan for another ten years was approved by the Company’s Board of Directors on February 1, 2008 and approved by the Company’s shareholders at the
Annual Meeting of Stockholders held on June 2, 2008. On March 21, 2016 at a special meeting of the shareholders, the Plan was amended to permit grant of common stock. Options are not transferable, are exercisable for 3 months after voluntary
resignation from the Company, and terminate immediately upon involuntary termination from the Company. The purchase price of shares subject to this Plan shall be determined at the time the options are granted, but are not permitted to be less than
85% of the fair market value of such shares on the date of grant.
On March 21, 2016, the Company’s shareholders approved a 1 for 10 reverse stock split, effective with trading on March 24,
2016. All share and per share information in the following tables has been adjusted to reflect the impact of this reverse stock split.
In August 2018, the Tengasco, Inc. 2018 Stock Incentive Plan (the “2018 Plan”) was adopted to continue to provide an incentive
to key employees, officers, directors, and consultants of the Company and its present and future subsidiary corporations, and to offer an additional inducement in obtaining the services of such individuals. The 2018 Plan contains the same
substantive terms as the Company’s previous stock incentive plan adopted in October, 2000 and thereafter amended until its expiration on January 10, 2018. The 2018 Plan provided an aggregate number of shares for which shares, options, and stock
appreciation rights may be issued equal to the number of shares that had been available for issuance in the previous plan upon expiration. The 2018 Plan was approved by a majority of the Company’s shareholders acting on written consents and the
shares thereunder were subject to Registration Statement on Form S-8 filed August 27, 2018.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The following table summarizes stock option activity in 2018 and 2017:
|
2018
|
2017
|
|||||||||||||||
|
Shares
|
Weighted
Average
Exercise
Price
|
Shares
|
Weighted
Average
Exercise
Price
|
|||||||||||||
|
Outstanding, beginning of year
|
30,000
|
$
|
3.73
|
37,500
|
$
|
4.70
|
||||||||||
|
Granted
|
—
|
$
|
—
|
—
|
$
|
—
|
||||||||||
|
Exercised
|
—
|
$
|
—
|
—
|
$
|
—
|
||||||||||
|
Expired/cancelled
|
(13,125
|
)
|
$
|
4.43
|
(7,500
|
)
|
$
|
8.40
|
||||||||
|
Outstanding, end of year
|
16,875
|
$
|
3.18
|
30,000
|
$
|
3.73
|
||||||||||
|
Exercisable, end of year
|
16,875
|
$
|
3.18
|
30,000
|
$
|
3.73
|
||||||||||
The following table summarizes information about stock options outstanding and exercisable at December 31, 2018:
|
Weighted Average
Exercise Price
|
Options Outstanding
(shares)
|
Weighted Average
Remaining Contractual Life
(years)
|
Options Exercisable
(shares)
|
|||||||||||
|
$
|
4.10
|
1,875
|
—
|
1,875
|
||||||||||
|
$
|
4.80
|
1,875
|
0.2
|
1,875
|
||||||||||
|
$
|
4.40
|
1,875
|
0.5
|
1,875
|
||||||||||
|
$
|
4.40
|
1,875
|
0.8
|
1,875
|
||||||||||
|
$
|
2.50
|
1,875
|
1.0
|
1,875
|
||||||||||
|
$
|
2.30
|
1,875
|
1.2
|
1,875
|
||||||||||
|
$
|
2.70
|
1,875
|
1.5
|
1,875
|
||||||||||
|
$
|
2.20
|
1,875
|
1.8
|
1,875
|
||||||||||
|
$
|
1.20
|
1,875
|
2.0
|
1,875
|
||||||||||
|
16,875
|
16,875
|
|||||||||||||
During 2018 and 2017, the Company issued no additional options to each of the three non-executive directors.
In addition, during 2018, the Company issued 19,366 shares of common stock to the Directors and to the CEO. The shares issued
to Directors was in lieu of stock options and vested immediately. The shares issued to the CEO was in lieu of a portion of the quarterly cash payment paid for service as the Company’s CEO and vested immediately. The company recorded compensation
expense of approximately $23,000 as a result of the stock issuances. In addition, during 2017, the Company issued 23,503 shares of common stock to the Directors and to the CEO. The shares issued to Directors was in lieu of stock options and vested
immediately. The shares issued to the CEO was in lieu of a portion of the quarterly cash payment paid for service as the Company’s CEO and vested immediately. The company recorded compensation expense of approximately $14,000 as a result of the
stock issuances.
13. Income Taxes
The Company did not have taxable income for the years ended December 31, 2018, and 2017.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying
consolidated statements of operations is as follows (in thousands):
|
Year Ended December 31, 2018
|
Total
|
|||
|
Statutory rate
|
21
|
%
|
||
|
Tax (benefit) expense at statutory rate
|
$
|
326
|
||
|
State income tax (benefit) expense
|
95
|
|||
|
Permanent difference
|
1
|
|||
|
Return to provision
|
152
|
|||
|
Net change in deferred tax asset valuation allowance
|
(591
|
)
|
||
|
Total income tax provision (benefit)
|
$
|
(17
|
)
|
|
|
Year Ended December 31, 2017
|
Total
|
|||
|
Statutory rate
|
34
|
%
|
||
|
Tax (benefit) expense at statutory rate
|
$
|
(278
|
)
|
|
|
State income tax (benefit) expense
|
(42
|
)
|
||
|
Permanent difference
|
1
|
|||
|
Impact of 2017 Tax Act
|
5,319
|
|||
|
Other
|
14
|
|||
|
Net change in deferred tax asset valuation allowance
|
(5,256
|
)
|
||
|
Total income tax provision (benefit)
|
$
|
(242
|
)
|
|
Management has evaluated the positions taken in connection with the tax provisions and tax compliance for the years included in
these financial statements. The Company believes that all of the positions it has taken will prevail on a more likely than not basis. As such no disclosure of such positions was deemed necessary. Management continuously estimates its ability to
recognize a deferred tax asset related to prior period net operating loss carry forwards based on its anticipation of the likely timing and adequacy of future net income.
At December 31, 2018, federal net operating loss carryforwards amounted to approximately $35.6 million, of which $34.6 million
expires between 2019 and 2037 which can offset 100% of taxable income and $1 million that has an indefinite carryforward period which can offset 80% of taxable income per year. The total net deferred tax asset was $130,000 at December 31, 2018 and
$242,000 at 2017. 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, 2018 primarily due to cumulative
losses incurred during the 3 years ended December 31, 2018. The Company recorded a full allowance against the deferred tax asset net of the AMT credit at December 31, 2017 primarily due to cumulative losses incurred during the 3 years ended December
31, 2017. The total valuation allowance December 31, 2018 was $11.5 million, and $12.1 million at December 31, 2017. As the Company adopted ASU 2016-09 during the first quarter of 2017, the excess tax benefits associated with certain stock
compensation deductions that have not been previously recognized were recorded to retained earnings net of valuation allowance. The effect on the valuation allowance on this adoption was an increase of $687,000 recorded to retained earnings.
Our open tax years include all returns filed for 2015 and later. In addition, any of the Company’s NOLs for tax reporting
purposes are still subject to review and adjustment by both the Company and the IRS to the extent such NOLs should be carried forward into an open tax year.
Comprehensive tax reform legislation enacted in December 2017, commonly referred to as the Tax Cuts and Jobs Act (the “2017 Tax
Act”), made significant changes to U.S. federal income tax laws. The 2017 Tax Act, among other things, reduces the corporate income tax rate to 21%, repeal of the corporate Alternative Minimum tax, partially limits the deductibility of business
interest expense and net operating losses, and allows the immediate deduction of certain new investments instead of deductions for depreciation expense over time. The Company had not completed its determination of the accounting implications of the
2017 Tax Act on its tax accruals. However the Company has reasonably estimated the effects of the 2017 Tax Act and recorded provisional amounts in its financial statements as of December 31, 2017. The Company recorded the following provisional
amounts for the effects of the 2017 Tax Act.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Beginning January 1, 2018, the U.S. corporate income tax rate was be 21%. The Company was required to recognize the impacts of this rate change
on its deferred tax assets and liabilities in the period enacted. The provisional tax effect of the change in tax rate was a decrease to the deferred tax asset of $5.3 million. However, as the Company has a full valuation allowance on its net
deferred tax asset, the deferred tax recognized due to the change in rate will be offset with a change in the valuation allowance. Therefore, there was no overall impact to the Financial Statements in 2017 due to this change in rate.
The 2017 Tax Act also repealed the corporate AMT for tax years beginning on or after January 1, 2018 and provides for existing alternative minimum
tax credit carryovers to be refunded beginning in 2018. The Company has approximately $260,000 in refundable credits, and it expects that a substantial portion will be refunded between 2018 and 2021. As 50% of the credit will be refunded when we
file the 2018 tax return, this amount is recorded as a current accounts receivable on the Balance Sheet at December 31, 2018, with balance of this refund recorded as a non-current accounts receivable.
The ultimate impact of the 2017 Tax Act may differ from the provisional amounts recorded due to additional information becoming
available, changes in interpretation of the 2017 Tax Act as well as additional regulatory guidance that may be issued. The company completed its review of the 2017 Tax Act in 2018, and there were no material changes in the measurement period.
The Company’s deferred tax assets and liabilities are as follows: (in thousands)
|
Year Ended December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Net
deferred tax assets – current:
|
||||||||
|
Bad debt
|
$
|
—
|
$
|
—
|
||||
|
Valuation allowance
|
—
|
—
|
||||||
|
Total deferred tax assets – current
|
$
|
—
|
$
|
—
|
||||
|
Net deferred tax assets (liabilities) – noncurrent:
|
||||||||
|
Net operating loss carryforwards
|
$
|
9,675
|
$
|
8,187
|
||||
|
Oil and gas properties
|
1,327
|
2,735
|
||||||
|
Property, Plant and Equipment
|
(163
|
)
|
419
|
|||||
|
Asset retirement obligation
|
592
|
616
|
||||||
|
Tax credits
|
130
|
260
|
||||||
|
Miscellaneous
|
45
|
92
|
||||||
|
Valuation allowance
|
(11,476
|
)
|
(12,067
|
)
|
||||
|
Total deferred tax assets – noncurrent
|
$
|
130
|
$
|
242
|
||||
|
Net deferred tax asset
|
$
|
130
|
$
|
242
|
||||
14. Quarterly Data and Share Information (unaudited)
The following tables sets forth for the fiscal periods indicated, selected consolidated financial data (In thousands, except per
share data)
|
Fiscal Year Ended 2018
|
1st Qtr
|
2nd Qtr
|
3rd Qtr
|
4th Qtr
|
||||||||||||
|
Revenues
|
$
|
1,367
|
$
|
1,475
|
$
|
1,654
|
$
|
1,375
|
||||||||
|
Net income (loss) from continuing operations
|
133
|
99
|
298
|
(88
|
)
|
|||||||||||
|
Income (loss) per common share from continuing operations
|
$
|
0.01
|
$
|
0.01
|
$
|
0.03
|
$
|
(0.01
|
)
|
|||||||
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
|
Fiscal Year Ended 2017
|
1st Qtr
|
2nd Qtr
|
3rd Qtr
|
4th Qtr
|
||||||||||||
|
Revenues
|
$
|
1,209
|
$
|
1,138
|
$
|
1,035
|
$
|
1,301
|
||||||||
|
Net income (loss) from continuing operations
|
(170
|
)
|
(230
|
)
|
(361
|
)
|
158
|
|||||||||
|
Income (loss) per common share from continuing operations
|
$
|
(0.02
|
)
|
$
|
(0.02
|
)
|
$
|
(0.03
|
)
|
$
|
0.01
|
|||||
15. Supplemental Oil and Gas Information (unaudited)
Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of
reserves quantities, as well as future production and discounted cash flows before income taxes, were determined by LaRoche Petroleum Consultants Ltd. All of the Company’s reserves were located in the United States.
Capitalized Costs Related to Oil and Gas Producing Activities
The table below reflects our capitalized costs related to our oil and gas producing activities at December 31, 2018 and 2017 (in
thousands):
|
Years Ended December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Proved oil and gas properties
|
$
|
6,503
|
$
|
5,704
|
||||
|
Unproved properties
|
23
|
—
|
||||||
|
Total proved and unproved oil and gas properties
|
$
|
6,526
|
$
|
5,704
|
||||
|
Less accumulated depreciation, depletion and amortization
|
(1,722
|
)
|
(984
|
)
|
||||
|
Net oil and gas properties
|
$
|
4,804
|
$
|
4,720
|
||||
Oil and Gas Related Costs
The following table sets forth information concerning costs incurred, including accruals, related to the Company’s oil and gas
property acquisition, exploration and development activities (in thousands):
|
Years Ended December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Property acquisitions proved
|
$
|
164
|
$
|
—
|
||||
|
Property acquisitions unproved
|
23
|
93
|
||||||
|
Exploration cost
|
590
|
69
|
||||||
|
Development cost
|
243
|
—
|
||||||
|
Total
|
$
|
1,020
|
$
|
162
|
||||
Results of Operations from Oil and Gas Producing Activities
The following table sets forth the Company’s results of operations from oil and gas producing activities (in thousands):
|
Years Ended December 31,
|
||||||||
|
2018
|
2017
|
|||||||
|
Revenues
|
$
|
5,871
|
$
|
4,683
|
||||
|
Production costs and taxes
|
(3,591
|
)
|
(3,444
|
)
|
||||
|
Depreciation, depletion and amortization
|
(722
|
)
|
(796
|
)
|
||||
|
Income (loss) from oil and gas producing activities
|
$
|
1,558
|
$
|
443
|
||||
In the presentation above, no deduction has been made for indirect costs such as general corporate overhead or interest
expense. No income taxes are reflected above due to the Company’s operating tax loss carry-forward position.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The following table sets forth the Company’s net proved oil and gas reserves and the changes in net proved oil and gas reserves
for the years ended December 31, 2016, 2017 and 2018. All of the Company’s proved reserves are located in the United States of America.
|
Oil (MBbl)
|
Gas (MMcf)
|
MBOE
|
||||||||||
|
Proved reserves at December 31, 2016
|
730
|
—
|
730
|
|||||||||
|
Revisions of previous estimates
|
195
|
—
|
195
|
|||||||||
|
Improved recovery
|
—
|
—
|
—
|
|||||||||
|
Purchase of reserves in place
|
—
|
—
|
—
|
|||||||||
|
Extensions and discoveries
|
47
|
—
|
47
|
|||||||||
|
Production
|
(102
|
)
|
—
|
(102
|
)
|
|||||||
|
Sales of reserves in place
|
—
|
—
|
—
|
|||||||||
|
Proved reserves at December 31, 2017
|
870
|
—
|
870
|
|||||||||
|
Revisions of previous estimates
|
223
|
—
|
223
|
|||||||||
|
Improved recovery
|
—
|
—
|
—
|
|||||||||
|
Purchase of reserves in place
|
13
|
—
|
13
|
|||||||||
|
Extensions and discoveries
|
86
|
—
|
86
|
|||||||||
|
Production
|
(98
|
)
|
—
|
(98
|
)
|
|||||||
|
Sales of reserves in place
|
—
|
—
|
—
|
|||||||||
|
Proved reserves at December 31, 2018
|
1,094
|
—
|
1,094
|
|||||||||
|
Proved developed reserves at:
|
||||||||||||
|
December 31, 2016
|
730
|
—
|
730
|
|||||||||
|
December 31, 2017
|
832
|
—
|
832
|
|||||||||
|
December 31, 2018
|
976
|
—
|
976
|
|||||||||
|
Proved undeveloped reserves at:
|
||||||||||||
|
December 31, 2016
|
—
|
—
|
—
|
|||||||||
|
December 31, 2017
|
38
|
—
|
38
|
|||||||||
|
December 31, 2018
|
118
|
—
|
118
|
|||||||||
The Company’s Proved Undeveloped Reserves at December 31, 2018 included 7 locations and at December 31, 2017 included 3
locations, and no locations at December 31, 2016 and 2015. During 2016 and 2015, all Proved Undeveloped locations were removed from the Company’s Proved Reserves primarily due to the low oil prices experienced during these years. Increases in
prices allowed the company to include 3 Proved Undeveloped locations in its December 31, 2017 reserves and 7 Proved Undeveloped locations in its December 31, 2018 reserves. Although the Company completed a well during 2018 that was not included in
Proved Reserves at the end of 2017 and therefore contributed to extensions and discoveries, the primary factor causing the revisions as well as the extensions and discoveries
during 2018 levels was related to higher oil prices that enabled the Company to consider certain properties as becoming economic or remaining economic longer and to consequently increase the oil volumes included in Proved Reserves.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The following table identifies the Company’s net proved reserve value by category and the respective present values, before income taxes,
discounted at 10% as a percentage of total proved reserves (in thousands):
|
Year Ended 12/31/2018
|
Year Ended 12/31/2017
|
Year Ended 12/31/2016
|
||||||||||||||||||||||||||||||||||
|
Oil
|
Gas
|
Total
|
Oil
|
Gas
|
Total
|
Oil
|
Gas
|
Total
|
||||||||||||||||||||||||||||
|
Total proved reserves year-end reserve report
|
$
|
13,976
|
—
|
$
|
13,976
|
$
|
8,170
|
—
|
$
|
8,170
|
$
|
5,815
|
—
|
$
|
5,815
|
|||||||||||||||||||||
|
Proved developed producing reserves (PDP)
|
$
|
12,534
|
—
|
$
|
12,534
|
$
|
7,065
|
—
|
$
|
7,065
|
$
|
5,397
|
—
|
$
|
5,397
|
|||||||||||||||||||||
|
% of PDP reserves to total proved reserves
|
90
|
%
|
—
|
90
|
%
|
87
|
%
|
—
|
87
|
%
|
93
|
%
|
—
|
93
|
%
|
|||||||||||||||||||||
|
Proved developed non-
producing reserves
|
$
|
739
|
—
|
$
|
739
|
$
|
1,082
|
—
|
$
|
1,082
|
$
|
418
|
—
|
$
|
418
|
|||||||||||||||||||||
|
% of PDNP reserves to total proved reserves
|
5
|
%
|
—
|
5
|
%
|
13
|
%
|
—
|
13
|
%
|
7
|
%
|
—
|
7
|
%
|
|||||||||||||||||||||
|
Proved undeveloped reserves (PUD)
|
$
|
703
|
—
|
$
|
703
|
$
|
23
|
—
|
$
|
23
|
$
|
—
|
—
|
$
|
—
|
|||||||||||||||||||||
|
% of PUD reserves to total proved reserves
|
5
|
%
|
—
|
5
|
%
|
—
|
—
|
—
|
—
|
—
|
—
|
|||||||||||||||||||||||||
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the
following table (in thousands):
|
Years Ended December 31,
|
||||||||||||
|
2018
|
2017
|
2016
|
||||||||||
|
Future cash inflows
|
$
|
65,871
|
$
|
39,889
|
$
|
27,253
|
||||||
|
Future production costs and taxes
|
(35,877
|
)
|
(23,343
|
)
|
(16,270
|
)
|
||||||
|
Future development costs
|
(2,833
|
)
|
(1,586
|
)
|
(553
|
)
|
||||||
|
Future income tax expenses
|
—
|
—
|
—
|
|||||||||
|
Future net cash flows
|
27,161
|
14,960
|
10,430
|
|||||||||
|
Discount at 10% for timing of cash flows
|
(13,185
|
)
|
(6,790
|
)
|
(4,615
|
)
|
||||||
|
Standardized measure of discounted future net cash flows
|
$
|
13,976
|
$
|
8,170
|
$
|
5,815
|
||||||
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The following are the principal sources of change in the standardized measure of discounted future net cash flows from the Company’s proved oil
and gas reserves (in thousands):
|
Years Ended December 31,
|
||||||||||||
|
2018
|
2017
|
2016
|
||||||||||
|
Balance, beginning of year
|
$
|
8,170
|
$
|
5,815
|
$
|
8,287
|
||||||
|
Sales, net of production costs and taxes
|
(2,611
|
)
|
(1,239
|
)
|
(2,037
|
)
|
||||||
|
Discoveries and extensions, net of costs
|
798
|
123
|
35
|
|||||||||
|
Purchase of reserves in place
|
143
|
—
|
—
|
|||||||||
|
Sale of reserves in place
|
—
|
—
|
(10
|
)
|
||||||||
|
Net changes in prices and production costs
|
4,304
|
1,780
|
(863
|
)
|
||||||||
|
Revisions of quantity estimates
|
2,180
|
1,611
|
(412
|
)
|
||||||||
|
Previously estimated development cost incurred during the year
|
210
|
—
|
—
|
|||||||||
|
Changes in future development costs
|
78
|
(228
|
)
|
196
|
||||||||
|
Changes in timing and other
|
(4
|
)
|
(164
|
)
|
(20
|
)
|
||||||
|
Accretion of discount
|
708
|
472
|
639
|
|||||||||
|
Net change in income taxes
|
—
|
—
|
—
|
|||||||||
|
Balance, end of year
|
$
|
13,976
|
$
|
8,170
|
$
|
5,815
|
||||||
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using
average sales prices along with estimates of the operating costs, production taxes and future development and abandonment cost (less salvage value) necessary to produce such reserves. Future income taxes were calculated by applying the statutory
federal and state income tax rates to pre-tax future net cash flows, net of the tax basis of the properties and utilizing available tax loss carryforwards related to oil and gas operations. The oil prices used for December 31, 2018, 2017, and 2016
were $60.21, and $45.83, and $37.35 per barrel of oil, respectively. The Company’s proved reserves as of December 31, 2018, 2017 and 2016 were measured by using commodity prices based on the twelve month unweighted arithmetic average of the first
day of the month price for the period January through December. No deduction has been made for depreciation, depletion, or any indirect cost such as general corporate overhead or interest expense.
16. Subsequent Events
On January 2, 2019, 4,962 common shares were issued in the aggregate to the Company’s three directors and the CFO and interim
CEO. This issuance will result in compensation expense of approximately $4,714 to be recorded during the quarter ended March 31, 2019.
In January 2019, the Company sold its equipment inventory for $150,000. The Company will record a gain on this sale of $45,000
during the quarter ended March 31, 2019.
F-25