UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

REPORT ON FORM 10-K

(Mark one)

[X} Annual Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal 

year ended December 31, 2012 or 

[ ] Transition Report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the 

transition period from __________ to __________.

Commission File No. 1-15555

TENGASCO, INC. 

(name of registrant as specified in its charter)

Delaware 87-0267438

(state or other jurisdiction of (I.R.S. Employer

Incorporation or organization) Identification No.)

11121 Kingston Pike, Suite E, Knoxville, TN 37934

(Address of Principal Executive Offices) (Zip Code)

Registrant’s telephone number, including area code: (865) 675-1554

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 [ ] [X] 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 [ ] [X] 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 [X] [ ] 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) [X] 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 nonaccelerated filer or smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” 

and “smaller reporting company” in Rule 12b-2 of the Exchange Act. 

Large Accelerated Filer [ ] Accelerated Filer [ ] 

Non-accelerated Filer [ ] Smaller Reporting Company [X]

(Do not check if a Smaller Reporting Company)

Indicate by checkmark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange 

Act). Yes [ ] No [X] 

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 $31 million (June 29, 2012 closing price $0.80).

The number of shares outstanding of the registrant’s $.001 par value common stock as of the close of 

business on March 15, 2013 was 60,842,413.
Table of Contents

PART I Page

Item 1. Business....................................................................... 5

Item 1A. Risk Factors.................................................................. 19

Item 1B. Unresolved Staff Comments................................................. 30

Item 2. Properties..................................................................... 30

Item 3. Legal Proceedings............................................................. 39

Item 4. Mine Safety Disclosures..................................................... 39

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder

Matters and Issuer Purchases of Equity Securities..................... 39

Item 6. Selected Financial Data.................................................... 40

Item 7. Management’s Discussion and Analysis of Financial Condition

and Results of Operations.................................................. 42

Item 7A. Quantitative and Qualitative Disclosures About Market Risk....... 49

Item 8. Financial Statements and Supplementary Data......................... 51

Item 9. Changes in and Disagreements With Accountants on Accounting

and Financial Disclosure................................................. 51

Item 9A. Controls and Procedures................................................. 51

Item 9B. Other Information.......................................................... 53

PART III

Item 10. Directors, Executive Officers and Corporate Governance........... 54

Item 11. Executive Compensation................................................. 61

Item 12. Security Ownership of Certain Beneficial Owners and Management

and Related Stockholders Matters....................................... 64

Item 13. Certain Relationships and Related Transactions, and Director 

Independence............................................................... 67

Item 14. Principal Accounting Fees and Services................................. 69

PART IV Item 15. Exhibits, Financial Statement and Schedules.......................... 71

SIGNATURES ........................................................... 75
1

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 2012 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)
2

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.
3

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. The purpose of the polymer gel treatment is to reduce excessive water production and increase 

oil or gas production from wells that produce from water-drive reservoirs. These 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 much 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 
4

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-dayof-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 and 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 rate 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.
5

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 on 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

ITEM 1. BUSINESS.

History of the Company

The Company was initially organized in Utah in 1916 under a name later changed to Onasco 

Companies, Inc. In 1995, the Company changed its name from Onasco Companies, Inc. by merging into 

Tengasco, Inc., a Tennessee corporation, formed by the Company solely for this purpose. At the 

Company’s Annual Meeting held on June 11, 2011, the stockholders of the Company approved an 

Agreement and Plan of Merger previously adopted by the Company’s Board of Directors 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 merger became

effective on June 12, 2011 and 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 oil exploration and production is in Kansas. The Company’s primary area of 

gas production is the Swan Creek field in Tennessee.
6

The Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”) owns and 

operates a 65-mile intrastate pipeline which it constructed to transport natural gas from the Company’s 

Swan Creek Field to customers in Kingsport, Tennessee.

The Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) 

operates treatment and delivery facilities using the latest developments in available treatment technologies 

for the extraction of methane gas from nonconventional sources for delivery through the nation’s existing 

natural gas pipeline system, including the Company’s pipeline system in Tennessee for eventual sale to 

natural gas customers.

The Company also had a management agreement with Hoactzin Partners, L.P. (“Hoactzin”) to 

manage Hoactzin’s oil and gas properties in the Gulf of Mexico offshore Texas and Louisiana (See

below, “General 4. Management Agreement with Hoactzin”). Peter E. Salas, the Chairman of the Board 

of Directors of the Company, is the controlling person of Hoactzin. He is also the sole shareholder and 

controlling person of Dolphin Management, Inc., the general partner of Dolphin Offshore Partners, L.P., 

which is the Company’s largest shareholder. This management agreement expired on December 18, 

2012.

General

1. The Kansas Properties

The Kansas Properties are located in central Kansas and as of December 31, 2012 include 196

producing oil wells, 21 shut-in wells, and 37 active disposal wells. Our management and staff have a 

great deal of Kansas exploration and production experience. We have onsite production management and

field personnel working in Kansas.

In 2012, the Company continued to focus on both development and exploration drilling. Many of 

the wells that were drilled were on leases that are still in effect because they are being held by existing 

production. The leases provide for a landowner royalty of 12.5%. Some wells are subject to an 

overriding royalty interest from 0.5% to 9%. Other than such wells bearing overriding royalties, the 

Company maintains a 100% working interest in most of its older wells and any undrilled acreage in 

Kansas. The terms for most of the Company’s newer leases in Kansas are from three to five years.

During 2012, the Company drilled 20 gross wells. The Company has a 100% working interest in 

all of the wells. The success rate of the 20 wells drilled by the Company in Kansas was 75% resulting in

15 producers and 5 dry holes. 

Kansas as a whole is of major significance to the Company. The majority of the Company’s 

current reserve value, current production, revenue, and future development objectives are centered in the 

Company’s ongoing interest in Kansas. By using 3-D seismic evaluation on existing locations owned by 

the Company in Kansas, the Company has added and continues to add proven direct offset locations. 

A. Kansas Ten Well Drilling Program

On September 17, 2007, the Company entered into a ten well drilling program with Hoactzin,
7

consisting of three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas

Properties (the “Program”). Under the terms of the Program, Hoactzin paid the Company $0.4 million for

each producing well and $0.25 million for each per dry hole. 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, referred to as a management 

fee. The fee paid to the Company by Hoactzin will increase to an 85% working interest when net 

revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s

purchase price (the “Payout Point”).

Nine of the ten wells in the program were completed as oil producers and during the 4th quarter 

2012 had gross production of approximately 36 barrels per day in total. Hoactzin paid a total of $3.85

million (the “Purchase Price”) for its interest in the Program resulting in the Payout Point being 

determined as $5.2 million. The Purchase Price paid by Hoactzin for its interest in the Program wells 

exceeded the Company’s actual drilling cost of approximately $2.6 million for the ten wells by more than 

$1 million.

In 2012, the wells from the Program produced 14.3 MBbl of which 9.1 MBbl were net to 

Hoactzin. As of December 31, 2012, net revenues received by Hoactzin from the Program totaled $4.6

million which leaves a balance of $0.6 million until the Payout Point is reached.

Although production level of the Program wells will decline over time in accordance with 

expected decline curves, based on the drilling results of the Program wells to date and the current price of 

oil, the Program wells are now expected to reach the Payout Point by late 2013 or early 2014. However, 

under the terms of the agreement reaching the Payout Point could be accelerated by applying 75% of the 

net profits Hoactzin receives from the methane extraction project developed by MMC at the Carter 

Valley, Tennessee landfill (the “Methane Project”), toward reaching the Payout Point. (The Methane 

Project is discussed in greater detail below.) 

The reserve information for the parties’ respective Ten Well Program interests as of December 

31, 2012 is indicated in the table below. Reserve reports are obtained annually and estimates related to 

those reports are updated upon receipt of the report. These calculations were made using commodity 

prices based on the twelve month arithmetic average of the first day of the month price for the period 

January through December 2012 as required by SEC regulations. The table below reflects eventual pay as 

occurring through the realization of proceeds at prices used in the reserve report dated December 31, 2012

of approximately $88.08 per barrel.
8

Reserve Information for Ten Well Program Interest as of December 31, 2012

Barrels Attributable to 

Party’s Interest

MBbl

Undiscounted Future 

Cash Flows Attributable 

to Party’s Interest

(in thousands)

Present Value of Future 

Cash Flows Discounted 

at 10% Attributable to 

Party’s Interest

(in thousands)

Tengasco 113.7 $6,657 $2,609

Hoactzin Partners, L.P. 29.9 $1,835 $1,098

B. Kansas Production

The Company’s gross oil production in Kansas increased from 241 MBbl in 2011 to 279 MBbl in 

2012. Approximately 30 MBbl of the 279 MBbl in 2012 were related to production from the 15 

successful wells drilled during 2012 and approximately 44 MBbl were related to production increases as a 

result of the 12 polymers that were performed during 2012. These increases were partially offset by 

normal production declines.

The capital projects undertaken by the Company in 2012 were initially funded by borrowings 

from the Company credit facility. However, these additional borrowings under the Company’s credit 

facility were repaid by December 31, 2012. 

2. The Tennessee Properties

In the early 1980’s Amoco Production Company owned numerous acres of oil and gas leases in 

the Eastern Overthrust in the Appalachian Basin, including the area now referred to as the Swan Creek 

Field. Amoco successfully drilled two natural gas discovery wells in the Swan Creek Field to the Knox 

Formation. In the mid-1980’s, however, development of this field was cost prohibitive due to a 

substantial decline in worldwide oil and gas prices which was further exacerbated by the high cost of 

constructing a necessary 23-mile pipeline to deliver gas from the Swan Creek Field to the closest market. 

In July 1995, the Company acquired the Swan Creek leases and began development of the field.

As of December 31, 2012, the Company has evaluated Swan Creek and nearby properties for the 

purpose of determining the value of continued development. In addition, the Company has evaluated the 

likelihood of realizing additional revenues from transportation of third party gas. As a result of these 

evaluations, Management has determined that Swan Creek and Pipeline are no longer considered core 

properties to the Company. At December 31, 2012, the Company was in the process of negotiating the 

sale of the Swan Creek and Pipeline assets. On March 1, 2013, the Company entered into an agreement 

with Swan Creek Partners LLC to sell the Company’s Swan Creek and Pipeline assets for $1.5 million. 

Final closing of this transaction is contingent upon customary due diligence as well as certain regulatory 

and easement holder approvals. 
9

A. Swan Creek Pipeline Facilities

The Company’s completed pipeline system is owned and operated by TPC and extends 65 miles 

from the Swan Creek Field to several meter stations in Kingsport, Tennessee. The pipeline system was 

built for a total cost of $16.4 million. The Company reviews the carrying value of the pipeline for 

impairment whenever events and circumstances indicate that the carrying value of an asset may not be 

recoverable from the estimated future cash flows expected to result from its use and eventual disposition. 

In cases where undiscounted expected future cash flows are less than the carrying value, an impairment 

loss is recognized equal to an amount by which the carrying value exceeds the fair value of assets. The 

factors considered by management in performing this assessment include current operating results, trends, 

and prospects, as well as the effects of obsolescence, demand, competition, and other economic factors. 

During 2010 there were indicators the pipeline may be impaired and the Company performed an 

assessment of the carrying value as of December 31, 2010 based on expected future cash flows. The 

assessment resulted in the Company recording an impairment of approximately $5.0 million for the year 

ended December 31, 2010. At December 31, 2012 management determined that an additional impairment 

of approximately $5.2 million was required. This determination at December 31, 2012 was based on 

negotiations with a third party regarding the sale of the pipeline assets as well as the Company’s inability 

to realize additional revenues from transportation of third party gas. 

The carrying value of the pipeline has been classified in assets held for sale and the associated

revenues and expenses net of taxes have been classified as discontinued operations. The carrying value of 

the pipeline included in assets held for sale was approximately $1.4 million and $6.9 million at December 

31, 2012 and 2011, respectively.

B. Swan Creek Production and Development

The Company has concluded based on the results of previously drilled wells and seismic data that 

drilling new gas wells in the Swan Creek Field would not achieve any significant increase in daily gas 

production totals from the Field. Current wells in production in the Swan Creek Field would be capable of 

and would likely produce all the remaining reserves in that Field. As a result, the Company has not 

drilled any new gas wells in the Swan Creek Field since 2004.

Because no drilling for natural gas in the Knox formation in Swan Creek is anticipated in the 

future, the current production levels less decline are the sole value of natural gas reserves and natural gas

production. The existing production from the current wells producing natural gas are showing typical 

Appalachian production declines, which exhibit a long-lived nature but more modest volumes. The 

experienced decline in actual production levels from existing wells in the Swan Creek Field was expected

and predictable. Although there can be no assurance, the Company expects these natural rates of decline 

in the future will be comparable to historical decline experienced over the 2010-2012 period.

As the Swan Creek assets represent only a small portion of the Company’s full cost pool, these 

asset will remain in oil and gas properties and related operations will continue to be classified in 

continuing operations. 
10

During 2012, the Company had 14 producing gas wells and 4 producing oil wells in the Swan 

Creek Field. Gross gas production from the Swan Creek Field during 2012 averaged 216 Mcfd compared 

to 145 Mcfd in 2011. Gross oil sales volumes from the Swan Creek field during 2012 averaged 

approximately 13 BOPD compared to 15 BOPD in 2011.

3. Methane Project

On October 24, 2006, the Company signed a twenty-year Landfill Gas Sale and Purchase 

Agreement (the “Agreement”) with BFI Waste Systems of Tennessee, LLC (“BFI”), an affiliate of Allied 

Waste Industries (“Allied”). In 2008, Allied merged into Republic Services, Inc. (“Republic”). The 

Company assigned its interest in the Agreement to MMC and provides that MMC will 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 and located about two miles from the Company’s 

pipeline. The Company installed a proprietary combination of advanced gas treatment technology to 

extract the methane component of the purchased gas stream. Methane is the principal component of 

natural gas and makes up about half of the purchased raw gas stream by volume. The Company 

constructed a pipeline to deliver the extracted methane gas to the Company’s existing pipeline (the 

“Methane Project”).

The total cost for the Methane Project, including pipeline construction, was approximately $4.5 

million. The costs of the Methane Project were funded primarily by (a) the money received by the 

Company from Hoactzin to purchase its interest in the Ten Well Program which exceeded the Company’s 

actual costs of drilling the wells in that Program by more than $1 million; (b) cash flow from the 

Company’s operations; and (c) $0.8 million of the funds the Company borrowed under its then credit 

facility with Sovereign Bank of Dallas, Texas (“Sovereign Bank”). Methane gas produced by the project 

facilities was initially mixed in the Company’s pipeline and delivered and sold to Eastman under the 

terms of the Company’s natural gas purchase and sale agreement with Eastman. The gas supply from this 

landfill is projected to grow over the years as the underlying operating landfill continues to expand and 

generate additional naturally produced gas, and for several years following the closing of the landfill, 

estimated by Republic to occur in 2041. Gas production will continue in commercial quantities up to 

approximately 14 years after closure of the landfill.

MMC declared startup of commercial operations on April 1, 2009. During the month of April, 

the facility produced and sold 14 MMcf of methane gas to Eastman Chemical Company (“Eastman”) and 

was online about 91% of the calendar month. System maintenance and landfill supply adjustments 

accounted for the remainder of the time. On May 1, 2009, Eastman advised MMC that it was suspending 

deliveries of the methane gas stream pending approval by the federal Environmental Protection Agency 

(“EPA”) of Eastman’s petition for inclusion of treated methane gas as natural gas within the meaning of 

the EPA’s continuous emission monitoring rules applicable to Eastman’s large boilers during the annual 

“smog season” beginning May 1st of each year. Although Eastman had begun seeking this approval in 

February, 2009, with the assistance of the Air Quality Department of the Tennessee Department of 

Environment and Conservation, the EPA had not acted by May 1, 2009. Eastman furnished to the EPA 

information provided by MMC that establishes that the methane gas stream is better fuel under the rule 

standards than even “natural” gas, which is technically defined in the smog season rules to include gas
11

being “found in geologic formations beneath the earth’s surface”. Because approval was not promptly 

received, MMC was forced to seek alternative markets for the methane gas stream.

The Company concluded an agreement for sale of the methane gas to Hawkins County Gas 

Utility District, a local utility commencing August 1, 2009 on a month to month basis. Effective 

September 1, 2009 the Company also began sales of its Swan Creek gas production to Hawkins County 

Gas Utility District, because the physical mixing of Swan Creek natural gas with MMC’s methane gas 

caused Eastman to suspend deliveries of both categories of gas as mixed. 

On August 27, 2009, the Company entered into a five-year fixed price gas sales contract with 

Atmos Energy Marketing, LLC, (“AEM”) in Houston, Texas, a nonregulated unit of Atmos Energy 

Corporation (NYSE: ATO) for the sale of the methane component of landfill gas produced by MMC at 

the Carter Valley Landfill. The agreement provides for the sale of up to 600 MMBtu per day. The 

contract was effective beginning with September 2009 gas production and ends July 31, 2014. The 

agreed contract price of over $6 per MMBtu was a premium to the then current five-year strip price for 

natural gas on the NYMEX futures market.

MMC’s plant is capable of remaining in operation for a full 24 hours per day. Daily production 

decreases during days when the plant operates less than 24 hours, whether due to any equipment or 

collection system supply issue. The primary reason experienced for less-than-24-hour operation since 

April 2009 has been frequent spiking in the oxygen content in the raw gas collected by Republic and 

delivered to the plant, rather than being caused by equipment malfunctions in MMC’s plant. Oxygen 

spikes shut down MMC’s equipment for safety reasons, as high oxygen gas streams become explosive 

under the compression required in our treatment process. In mid-2010 the oxygen spikes increased from 

occasional spikes to an almost constant level of oxygen that caused longer downtime to our equipment. 

MMC’s plant had minimal production of sales methane during the fourth quarter of 2010 of 

approximately 5,500 MMBTU of methane gas for an average of 60 MMBTU per day. The MMC plant 

had no production of methane during the third quarter 2010. During the second quarter in 2010, the 

facility produced approximately 27,000 MMBtu of methane, an average of 300 MMBtu per day. In the 

first quarter of 2010, the facility had produced about 19,600 MMBtu, an average of 220 MMBtu per day.

These problems continued throughout 2011, with average production being 81MMBtu per day for 

the twelve month period ending December 31, 2011 or a total yearly production of 29,469 MMBtu. The 

final two months of 2011 had no production at the methane plant, due to additions being made to MMC’s 

facility to allow installation and fueling of the electric generator described below. 

In order to address the issue of significant plant downtime due to oxygen levels, MMC sought to 

eliminate the recycling of a process methane gas stream within the methane plant. That recycling had the 

effect of increasing the oxygen percentages at plant inlet when it was recycled to the plant inlet in order to 

extract some still-remaining methane. By ceasing use of that recycle stream, methane extraction 

efficiency would be reduced, but run time would be increased by avoiding some oxygen-caused 

shutdowns for safety. MMC determined the recycle gas stream could be repurposed to be used to fuel an 

electric generator onsite, which would offset electric utility costs at the methane plant, as well as 

providing an additional revenue source. In April 2011, MMC purchased a Caterpillar genset from 

Parkway Services Group of Lafayette, Louisiana which was delivered in late 2011 and installed at the 
12

methane 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 of 

its methane extraction facilities. The electricity generated is sold under a ten year firm price contract with

Holston Electric Cooperative, Inc., the local distributor, and Tennessee Valley Authority through TVA’s 

Generation Partners program. That program accepted generated renewable power only 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 pays 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). Current price paid to MMC is $.129 per KWH. 

The contract terminates in January 2022 but can be extended for an additional ten years at a purchase 

price to be negotiated at that time. Methane gas sales will continue under the Atmos contract

simultaneously with electricity sales and the same one-eighth royalty on electricity revenues will be paid 

to the landfill owner as is paid on methane revenues. The electric generation also reduces oxygen input to 

the methane plant. Although a portion of the gas used for generation of electricity will not be available 

for methane extraction, the use of the gas for electricity generation is equivalent to sale of the methane for 

almost $15 per MMBtu, more than double the price currently received for methane sales and more than 

four times the current natural gas spot market price. During 2012, the gas sales portion of MMC was 

online approximately 59% of the time resulting in gas sales revenues net of royalty of $0.219 million. 

During 2012, the electric sales portion of MMC was online approximately 46% of the time resulting in 

electric sales revenues net of royalty of $0.447 million. 

On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well 

Program (the “Program”), pursuant to a separate agreement with the Company was conveyed a 75% net 

profits interest in the Methane Project. Any net profits from the Methane Project, if received by Hoactzin, 

would be applied towards the determination of the Payout Point (as defined above) for the Ten Well 

Program. When the Payout Point is reached from either the revenues from the wells drilled in the 

Program or the Methane Project or a combination thereof, Hoactzin’s net profits interest in the Methane 

Project will decrease to 7.5%. The agreed method of calculation of net profits takes into account specific 

costs and expenses as well as gross revenues for the project. As a result of the startup costs and ongoing 

operating expenses, and reduced production levels discussed above, no net profits as defined have been 

generated from project startup in April, 2009 through December 31, 2012 for payment to Hoactzin under 

the net profits interest conveyed. As of the date of this report, all payments applied to reaching the 

Payout Point have been generated from the Program.

4. Management Agreement with Hoactzin

On December 18, 2007, the Company entered into a Management Agreement with Hoactzin. On 

that same date, the Company also entered into an agreement with Charles Patrick McInturff employing 

him as a Vice-President of the Company. Pursuant to the Management Agreement with Hoactzin, Mr. 

McInturff’s duties while he is employed as Vice President of the Company included the management on 

behalf of Hoactzin 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 consideration for the 

Company entering into the Management Agreement, Hoactzin agreed that it would
13

be responsible to reimburse the Company for the payment of one-half of Mr. McInturff’s salary, as well 

as certain other benefits he receives during his employment by the Company. In further 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 term of the Management Agreement ends on the earlier of the date Hoactzin sells its 

interest in its managed properties or five years (December 2012). The Management Agreement expired

on December 18, 2012. As of the date of this Report, the Company is assisting Hoactzin with becoming 

operator of record of these wells and transferring the corresponding bonding liability from the Company 

to Hoactzin. The Company has entered into a transition agreement with Hoactzin whereby Hoactzin and 

its controlling member are indemnifying Tengasco for any costs or liabilities incurred by Tengasco 

resulting from such assistance, or the fact that Tengasco is still the operator of record on certain of these 

wells.

The Company became the operator of certain properties owned by Hoactzin in connection with 

the Management Agreement. The Company obtained from IndemCo, over time, bonds in the face amount 

of approximately $10.7 million for the purpose of covering plugging and abandonment obligations for 

operated properties located in federal offshore waters in favor of the Bureau of Ocean Energy 

Management (“BOEM”), as well as certain private parties. On October 12, 2012, the BOEM terminated 

$1.1 million of these bonds leaving a balance of approximately $9.6 million at December 31, 2012.

In connection with the issuance of these bonds the Company entered into a Payment and 

Indemnity Agreement with IndemCo that guarantees payment of any bonding liabilities incurred by 

IndemCo. Dolphin Direct Equity Partners, LP co-signed the Payment and Indemnity Agreement, thereby 

becoming jointly and severally liable with the Company for the obligations to IndemCo. Hoactzin has 

provided $6.6 million in cash to IndemCo as collateral for the obligations. Dolphin Direct Equity

Partners is a private equity fund controlled by Peter E. Salas that has a significant economic interest in 

Hoactzin. 

As operator, the Company had routinely contracted in its name for goods and services with 

vendors in connection with its operation of the Hoactzin properties. In practice, Hoactzin paid directly 

these invoices for goods and services that are contracted in the Company’s name. During late 2009 and 

early 2010, Hoactzin undertook several significant operations, for which the Company contracted in the

ordinary course. As a result of the operations performed in late 2009 and early 2010, Hoactzin currently 

has significant past due balances to several vendors, a portion of which are included on the Company’s 

balance sheet. Payables related to these past due and ongoing operations remained outstanding at the end 

of 2012 and 2011 in the amount of $0.325 million and $0.265 million respectively. Because this amount 

is material, the Company has recorded the Hoactzin-related payables and the corresponding receivable 

from Hoactzin as of December 31, 2012 and 2011 in its Consolidated Balance Sheets under “Accounts 

payable – other” and “Accounts receivable – related party”. During the quarters ended September 30, 

2012 and December 31, 2012, Hoactzin had not made payments to reduce these past due balances. Based 

on these circumstances, the Company has elected to establish an allowance in the amount of $0.257

million of the $0.325 million balance outstanding at December 31, 2012. The $0.068 million difference 

between the balance and the allowance represent invoices paid by Hoactzin in early 2013. 
14

The Company as designated operator was administratively issued an “Incidence of NonCompliance” by BOEM concerning one of the Hoactzin wells operated by the Company pursuant to the 

Management Agreement. This action calls for payment of a civil penalty of $386,000 for the late filing of 

certain reports in 2011 by a contractor on the facility. The work to be reported had been timely 

performed, but the reports were not filed by the contractor. The contractor has since filed for bankruptcy. 

The Company was not at fault in this matter but is made administratively liable due to the status as 

designated operator of the well. The Company has filed an appeal of this action in order to attempt to 

significantly reduce the civil penalty. This appeal required a fully collateralized appeal bond to stay

payment of the obligation until the appeal is determined. On November 1, 2012, the Company posted and 

collateralized this bond with RLI Insurance Company. If the bond was not posted, the appeal would be 

administratively denied and the order to the Company as operator to pay the $386,000 penalty would be 

final. While the Company believes it will ultimately prevail in the appeal process, it is reasonably 

possible to expect that the Company may be required to pay a portion of this penalty. The Company 

estimates the range of this possible payment to be between zero and $386,000. 

No funds have been advanced by Tengasco to pay any obligations of Hoactzin. No borrowing 

capability of Tengasco has been used by the Company in connection with its obligations under the 

Management Agreement, except for those funds used to collateralize the appeal bond with RLI Insurance 

Company. The Management Agreement expired on December 18, 2012. 

5. Other Areas of Development

The Company may review potential acquisitions of additional existing oil and gas production in 

areas of Kansas, Oklahoma, and Texas. However, at the time of this report, the Company remains fully 

focused on development of the Company’s current Kansas holdings.

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. The principal 

markets for the Company’s natural gas and methane production are local utilities, private industry endusers, and gas marketing 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 Refining”) in Kansas City, Kansas and 

to National Cooperative Refinery Association (“NCRA”) in McPherson, Kansas. Both Coffeyville 

Refining and NCRA 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 purchases prices offered by the refineries fluctuate from time to time. 
15

Crude oil produced by the Company in Tennessee is sold to Clearfield Appalachian (“Clearfield). 

Clearfield is solely responsible for transportation to the refinery of the oil they purchase.

Gas production from the Swan Creek Field can presently be delivered through the Company’s 

completed pipeline to the Powell Valley Utility District in Hancock County, Hawkins County Gas Utility, 

Eastman and BAE in Sullivan County, other industrial customers in the Kingsport area, as well as gas 

marketing companies. The Company has acquired all necessary regulatory approvals and necessary 

property rights for the pipeline system. The Company’s pipeline can provide transportation service not 

only for gas produced from the Company’s wells, but also for small independent producers in the local 

area as well or other pipelines that may be connected to the Company’s pipeline in the future. 

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 companies as available in 

the Swan Creek Field area and various drilling contractors in Kansas.

Distribution Methods of Products or Services

Crude oil is normally delivered to refineries in Tennessee and Kansas by tank truck and natural 

gas is distributed and transported by pipeline.

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

Competition 

The Company’s contemplated oil and gas exploration activities in the States of Tennessee and 

Kansas 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.

The Company has numerous competitors in the State of Tennessee that are in the business of 

exploring for and producing oil and natural gas in Kentucky and East Tennessee areas. 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.

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.
16

The Company anticipates no difficulty in procuring well drilling permits in any state. They are 

usually issued within one week of application. 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 and the United 

States natural gas 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 Refining and NCRA, 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 purchase prices offered by the refineries fluctuate from time to time.

The Company is presently dependent upon a small number of customers for the sale of gas from 

the Swan Creek Field and the Methane Project. These customers are principally gas marketing 

companies, utility districts, and industrial customers in the Kingsport area with which the Company may 

enter into gas sales contracts.

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. In addition the transportation service offered by TPC is 

subject to regulation by the Tennessee Regulatory Authority to the extent of certain construction, safety,
17

tariff rates and charges, and nondiscrimination requirements under state law. These requirements are 

typical of those imposed on regulated common carriers or utilities in the State of Tennessee or in other 

states. TPC presently has all required tariffs and approvals necessary to transport natural gas to all 

customers of the Company.

The City of Kingsport, Tennessee has enacted an ordinance granting to TPC a franchise for 

twenty years (expires June 20, 2020) to construct, maintain and operate a gas system to import, transport, 

and sell natural gas to the City of Kingsport and its inhabitants, institutions and businesses for domestic, 

commercial, industrial and institutional uses. This ordinance and the franchise agreement it authorizes 

also require approval of the Tennessee Regulatory Authority under state law. The Company will not 

initiate the required approval process for the ordinance and franchise agreement until such time that it can 

supply gas to the City of Kingsport. Although the Company anticipates that regulatory approval would be 

granted, there can be no assurances that it would be granted, or that such approval would be granted in a 

timely manner, or that such approval would not be limited in some manner by the Tennessee Regulatory 

Authority.

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, the cost of which is 

approximately $10,000 per well.

The State of Tennessee also requires the posting of a bond to ensure that the Company’s wells are 

properly plugged when abandoned. A separate cash $2,000 bond is required for each well drilled. The 

Company currently has the requisite amount of cash bonds in effect and are secured by a certificate of 

deposit in the amount of $120,500.

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. 
18

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 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 and at strategic

locations along the pipeline 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 no 

doubt be enacted and revisions will be made in current laws. No assurance can be given as to that affect

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

The Company presently has 25 full time employees and no part-time employees.
19

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. 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. 

ITEM 1A. RISK FACTORS

In addition to the other information included in this Form 10-K, the following risk factors should 

be considered in evaluating the Company’s business and future prospects. The risk factors described 

below are not exhaustive and you are encouraged to perform your own investigation with respect to the 

Company and its business. You should also read the other information included in this Form 10-K, 

including the financial statements and related notes. 

The Company’s indebtedness, global recessions, and 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, 2012, the outstanding principal amount of the Company’s indebtedness 

under its credit facility with F&M Bank & Trust Company (“F&M Bank”) was approximately $10.1

million. The 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
20

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 disruption in 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 F&M 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 sharp 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 

F&M 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 

conditions.

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 
21

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, if the 

borrowing base is reduced, it would be required to pay down its borrowings under the revolving credit 

facility so that outstanding borrowings do not exceed the reduced borrowing base. This requirement could 

further reduce the cash available to the Company for capital spending and, if the Company did not have 

sufficient capital to reduce its borrowing level, could cause the Company to default under its revolving 

credit facility

The Company’s Credit Facility is Subject to Variable Rates of Interest, Which Could Negatively 

Impact the Company.

Borrowings under the Company’s credit facility with F&M 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, F&M 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.

 
22

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, and has an 

accumulated deficit of $25.6 million as of December 31, 2012. In 2009, the Company recorded a net loss 

of $2.0 million. In 2010, the Company had a profit before pipeline impairment of $1.3 million, but due to 

a non-cash pipeline impairment of $5 million ($3.3 million net of tax effects) the Company recorded a net 

loss of $1.7 million. The Company also recorded a $0.6 million non-cash unrealized gain on derivatives 

($0.4 million net of tax effects). Net of both the non-cash impairment and the non-cash unrealized gain 

on derivatives the Company would have recorded an adjusted net income of $0.9 million. In 2011, the 

Company recorded net income of $4.7 million. In 2012, the Company recorded a net loss of $0.1 million 

primarily due to a non-cash pipeline impairment of $5.2 million or $3.4 million net of tax effects. 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. 
23

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 and Tennessee oil and natural gas 

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 properties proved reserves will decline materially as 

production from these properties continues. The Company’s future oil and natural gas production is 

therefore 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 have a chilling 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 is particularly so if the price of oil declines 

sharply as it did during the period from mid-2008 through January 2009.
24

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 or of gas, or both, may be 

materially revised downward from time to time. As an example, the Company’s proved Swan Creek gas 

reserves calculation has been revised downward in the past as a result of removal of portions of the 

Company’s reported gas reserves from the “proved undeveloped category” (“PUD”) and the “proved 

developed nonproducing” (“PDNP”) categories. This downward revision was based on the Company’s

determination that additional drilling or development of Swan Creek may not occur in the foreseeable 

future because the economic returns from such drilling or development would not be favorable when 

compared to the costs and anticipated results of such activity. Although that particular revision at this 

time will not have a significant impact on overall results of operations in view of the relatively small 

portion of the Company’s current business and assets founded in Swan Creek, other future revisions in oil 

and gas reserves, may be significant and materially reduce oil or gas reserves.

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.

There is a Risk That the Company May Be Required to Write Down the Carrying Value of its 

Pipeline or Methane Facilities.

The Company’s Pipeline and Methane facility assets are subject to review for impairment 

whenever events or changes in circumstances indicate that their carrying amount may not be recoverable.
25

 The carrying amount is not recoverable if it exceeds the sum of the undiscounted cash flows expected to 

result from the use and eventual disposition of the pipeline or methane facility assets. Should this occur, 

the assets carrying amount will be reduced to its fair value and the excess over fair value to net of any tax 

effects, will be charged to earnings. This expense may not be reversed in future periods. During 2010 and 

2012, the Company incurred writedowns of its pipeline asset of $5.0 million and $5.2 million, 

respectively and approximately $3.3 million and $3.4 million net of tax effect in 2010 and 2012, 

respectively. These writedowns resulted from the Company’s assessment that cash flows generated from

the pipeline were insufficient to recover the pipeline’s net book value. During the fourth quarter of 2010

and 2012, the Company received expressions of interest from potential purchasers of the pipeline asset 

which were significantly below the asset’s pre-writedown net book value. These expressions of interest as 

well as the Company’s inability to realize additional revenues from transportation of third party gas

indicated that the carrying amount of the pipeline may not be recoverable. The carrying value of the 

pipeline asset at December 31, 2012 is approximately $1.4 million. The pipeline asset is classified as an 

asset held for sale.

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

At December 31, 2012, 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 of 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.

Shortages of Oil Field Equipment, Services and 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. Higher oil prices in Kansas have currently

stimulated and increased demand and this has resulted in increased prices for drilling rigs, crews and 

associated supplies, equipment and services, as well as increased potential that the Company’s 

experienced employee base in Kansas conducting field operations may be offered employment by 
26

competing companies and the Company may not be capable of replacing such departing personnel at 

existing salary levels, or at all. 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 have to 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 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, 

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 and natural gas and the Company’s

transportation and other activities 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 
27

facilities, injury to persons, loss of life or damage to property or to 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 Operations from Non-conventional Reserves Involve 

Substantial Cost and are Subject to Various Economic, Operational, and Regulatory Risks.

The Company’s operations in projects involving the extraction of methane gas from nonconventional reserves such as landfill gas streams, require investment of substantial capital and are 

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 is 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. These projects are also subject to the risk that the products manufactured may 

not be accepted for transportation in common carrier gas transportation facilities, although the products

meet specified requirements for such transportation, or may be accepted on such terms that reduce the 

returns of such projects to the Company. These projects are also subject to the risk that the product 

manufactured may not be accepted by purchasers thereof from time to time and the viability of such 

projects would be dependent upon the Company’s ability to locate a replacement market for physical 

delivery of the gas produced from the project. 

The Company’s methane extraction business is the subject of a patent granted to the Company. 

There can be no assurance that our existing patent will not be invalidated, circumvented or 

challenged, or that we will be issued any patents sought in the future, or that the rights granted or 

to be granted under any patents will provide us competitive advantages. 

We have been granted one U.S. patent and have a continuation U.S. patent application pending 

relating to certain aspects of our methane extraction technology and we may seek additional patents on

future innovations. 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, that patents will be issued for our continuation patent pending, that the rights granted under 

the patents will provide us competitive advantages, or that our current and future patent applications will 

be granted. 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
28

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.

Jeffrey R. Bailey, the Company’s Chief Executive Officer, other 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 specifically including engineering, 

petrophysical analysis, and well completion design. To the extent that their services become unavailable,

the Company would be required to retain other and additional qualified personnel to perform these 

multiple services in several 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 or retention agreements 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 MKT, 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
29

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 Management, Inc. the general partner of Dolphin Offshore Partners, L.P. 

(“Dolphin”), and a member of SSB Ventures LLC (“SSB”) which is the Company’s largest shareholder. 

At March 15, 2013, Mr. Salas through Dolphin and SSB controls 21,057,492 shares of the Company’s 

common stock and had options granting him the right to acquire an additional 150,000 shares of common 

stock. His ownership and voting control of approximately 35% 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.

As of March 15, 2013 the Company had 60,842,413 shares of common stock outstanding of 

which 22,076,212 shares were held by affiliates. In addition, options to purchase 991,000 shares of 

unissued common stock were granted under the Tengasco, Inc. Stock Incentive Plan of which options to 

purchase 831,000 shares were vested at March 15, 2013.

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 Could 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 61 million shares have been issued. The potential issuance of 

the approximately 39 million remaining authorized but unissued shares of common stock may create 
30

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 MKT, the Company’s charter authorizes the Board of Directors 

to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any 

further approval from holders of the Company’s common stock. Any preferred stock that is issued may 

rank ahead of the Company’s common stock in terms of dividends, priority and liquidation premiums and 

may have greater voting rights than the Company’s common stock.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES.

Property Location, Facilities, Size and Nature of Ownership.

General

The Company leases its principal executive offices, consisting of approximately 6,134 square feet 

located at 11121 Kingston Pike, Suite E, Knoxville, Tennessee at a rental of $7,294 per month, expiring 

on July 31, 2013 and an office in Hays, Kansas at a rental of $750.00 per month that is currently a month 

to month lease.

Although the Company does not pay property taxes on its Swan Creek leases, it pays ad valorem 

taxes on its Kansas Properties. The Company has general liability insurance for its Kansas and Tennessee

Properties. As of December 31, 2012, the Company does not have an interest in producing or nonproducing properties in any state outside of Kansas and Tennessee.

Kansas Properties

The Kansas Properties as of December 31, 2012 contained approximately 20,600 gross acres in 

the vicinity of Hays, Kansas. Of these 20,600 gross acres, 13,751 acres were held by production and 

6,849 acres were undeveloped.

In 2012, the Company continued to focus on retaining properties with geologic value. Many of 

these leases are still in effect because they are being held by production. These leases provide for a 

royalty of 12.5%. Some wells are subject to an overriding royalty interest from 0.5% to 9%. The 

Company maintains a 100% working interest in most of its older wells and any undrilled acreage in 

Kansas. The primary term for most of the Company’s newer leases in Kansas is from three to five years 
31

from the date of the lease.

During 2012, the Company drilled and completed as producers 15 wells, and also drilled 5 dry 

holes in Kansas.

Kansas as a whole is of major significance to the Company. The majority of the Company’s

current reserve value, current production, revenue, and future development objectives are centered in the 

Company’s ongoing interests in Kansas. By using 3-D seismic evaluation on existing locations owned by 

the Company in Kansas, the Company has added and continues to add proven direct offset locations. As 

a whole, our collective central Kansas holdings (see map below) are of major significance and as a group 

the most materially important segment of the Company as Kansas accounted for 94.4% of the Company’s 

revenue (i.e. $19.4 million of $20.6 million) and 95.4% of the Company’s total oil and gas production

during 2012.

The map below indicates the location of the 10 counties in Kansas in which the Company had production 

as of December 31, 2012.
32

Tennessee Properties

The Company’s Swan Creek leases are on approximately 8,342 gross acres in Hancock and 

Claiborne Counties in Tennessee. Of these 8,342 gross acres, 3,160 acres were held by production and 

5,182 acres were undeveloped. At the time of this Report, all of the Company’s Tennessee production is 

from Hancock County.

Reserve and Production Summary

The following tables indicate the county breakdown of 2012 production and reserve values as of 

December 31, 2012. 

Production by Area

Area Gross Production

MBOE

Average Net

Revenue Interest

Percentage of Total 

Oil Production

Rooks County, KS 188.5 0.809373 63.4%

Trego County, KS 44.5 0.809895 15.0%

Ellis County, KS 11.5 0.815278 3.9%

Graham County, KS 11.4 0.867799 3.9%

Barton County, KS 7.0 0.817461 2.4%

Russell County, KS 5.2 0.805623 1.7%

Pawnee County, KS 4.2 0.780379 1.4%

Rush County, KS 3.0 0.868892 1.0%

Osborne County, KS 2.0 0.588999 0.7%

Stafford County, KS 1.5 0.716252 0.5%

Total KS 278.8 93.9%

Hancock County, TN 18.0 0.712483 6.1%

Total 296.8 100%
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

33

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

Area Proved 

Developed

Proved

Undeveloped

Proved 

Reserves

% of 

Total

Rooks County, KS $ 29,146 $ 4,439 $ 33,585 62.3%

Trego County, KS 8,700 517 9,217 17.1%

Graham County, KS 1,077 1,961 3,038 5.6%

Ellis County, KS 2,229 - 2,229 4.1%

Barton County, KS 1,708 307 2,015 3.8%

Russell County, KS 1,016 - 1,016 1.9%

Pawnee County, KS 262 647 909 1.7%

Rush County, KS 656 - 656 1.2%

Stafford County, KS 98 179 277 0.5%

Osborne County, KS 201 - 201 0.4%

Total KS 45,093 8,050 53,143 98.6%

Hancock County, TN 768 - 768 1.4%

Total $ 45,861 $ 8,050 $ 53,911 100%

Reserve Analyses

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

2012 and 2011, 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 
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

34

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.

Total Proved Reserves as of December 31, 2012

Producing Non Producing Undeveloped Total

Natural gas (MMcf) 22.1 - - 22.1

Oil (MBbl) 1,743.1 78.6 390.8 2,212.5

Total (MBOE) 1,746.8 78.6 390.8 2,216.2

Future net cash flows before income 

taxes discounted at 10% (in thousands)

$ 42,626 $ 3,235 $ 8,050 $ 53,911

Total Proved Reserves as of December 31, 2011

Producing Non-producing Undeveloped Total

Natural gas (MMcf) 3.7 - - 3.7

Oil (MBbl) 1,838.1 100.7 651.9 2,590.7

Total proved reserves (MBOE) 1,838.7 100.7 651.9 2,591.3

Future net cash flows before income 

taxes discounted at 10% (in thousands)

$ 46,621 $ 3,977 $ 19,165 $ 69,763

Historically, all drilling has primarily been funded by cash flows from operations with 

supplemental funding provided by the Company’s credit facility. During 2012, approximately 57 MBbl 

of proved undeveloped reserves that existed at December 31, 2011 were converted into proved developed 

reserves from drilling and completion. All proved undeveloped reserves included in the Company’s 

report at December 31, 2012 and 2011 related to oil prospects in Kansas. During 2011, approximately 

140 MBbl of proved undeveloped reserves that existed at December 31, 2010 were converted into proved 

developed reserves.
35

The oil and natural gas prices after basis adjustments used in our December 31, 2012 reserve 

valuation were $88.08 per Bbl and $2.76 per Mcf. The oil and natural gas prices after basis adjustments 

used in our December 31, 2011 reserve valuation were $88.53 per Bbl and $4.16 per Mcf. The per Bbl 

decrease in oil price and the reduction of identified proved undeveloped locations were the primary 

factors in the decreased 2012 reserve volumes and values as compared to 2011 levels. (Refer to Note 16, 

Supplemental Oil and Gas Information, Standardized Measure of Discounted Future Net Cash Flows in 

the Company’s Notes to Consolidated Financial Statements for additional reserve information.)

The prices used in calculating the estimated future net revenue attributable to proved reserves do 

not reflect market prices for natural gas and oil production sold subsequent to December 31, 2012. 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.

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 CEO and the 

Vice President responsible for management of Hoactzin’s properties located offshore Texas/Louisiana 

each have extensive professional engineering experience evaluating both domestic and international 

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. 
36

Production

The following tables summarize for the past three fiscal years the volumes of oil and gas 

produced, the Company’s operating costs and the Company’s average sales prices for its oil and gas. The 

information includes volumes produced to royalty interest or other parties’ working interest.

Kansas

Years Ended 

December 31,

Gross 

Production

Net Production Cost of 

Production

(per BOE) 

Average Sales 

Price

Oil

(MBbl)

Gas

(MMcf)

Oil

(MBbl)

Gas

(MMcf)

Oil 

(Bbl)

Gas

(Per 

Mcf)

2012 278.8 - 225.9 - $ 22.77 $ 86.90 -

2011 240.8 - 185.7 - $ 18.31 $ 88.15 -

2010 224.2 - 169.5 - $ 17.33 $ 72.14 -

Tennessee

Years Ended 

December 31,

Gross 

Production

Net Production Cost of 

Production

(per BOE)

Average Sales 

Price

Oil

(MBbl)

Gas

(MMcf)

Oil

(MBbl)

Gas

(MMcf)

Oil 

(Bbl)

Gas

(Per 

Mcf)

2012 4.9 78.8 3.5 56.2 $ 46.85 $ 88.29 $ 3.35

2011 5.4 52.8 3.8 41.6 $ 46.37 $ 87.33 $ 4.28

2010 6.2 59.6 4.2 24.7 $ 32.62 $ 71.05 $ 4.90

Oil and Gas Drilling Activities

Kansas

In 2012, the Company drilled 15 successful wells, and 5 dry holes. The successful wells drilled 

in Kansas in 2012 contributed approximately 30 MBbl of gross production. The Company has a 100% 

working interest in each of these successful wells. The Company continues to pursue incremental 
37

production increases where possible in the older wells, by using recompletion techniques to enhance 

production from currently producing intervals. During 2012, the Company polymered 12 wells which 

contributed approximately 44 MBbl of gross production.

Tennessee

In 2012 the Company did not drill any new wells in the Swan Creek Field or on any other 

Company acreage in Tennessee. 

Gross and Net Wells

The following tables set forth the fiscal years ending December 31, 2012, 2011 and 2010 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,

2012 2011 2010

Kansas Gross Net Gross Net Gross Net

Productive Wells 15 15 16 16 5 5

Dry Holes 5 5 9 9 5 4

Salt Water Disposal - - - - - -

Tennessee

Dry Holes - - 1 1 - -

Productive Wells

The following table sets forth information regarding the number of productive wells in which the

Company held a working interest as of December 31, 2012. 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 interest 

the Company owns in the gross wells.
38

Gas Oil

Gross Net Gross Net

Kansas - - 217 213

Tennessee 12 10 4 3

Total 12 10 221 216

Developed and Undeveloped Oil and Gas Acreage

As of December 31, 2012 the Company owned 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

Gross Acres Net Acres Gross Acres Net Acres

Kansas 13,751 11,018 6,849 5,822

Tennessee 3,160 2,251 5,182 4,534

Total 16,911 13,269 12,031 10,356

The following table identifies the number of gross and net undeveloped acres as of December 31, 2012

that will expire, by year, unless production is established before lease expiration or unless the lease is 

renewed.

Kansas Tennessee Total

Gross Net Gross Net Gross Net

2013 2,360 2,006 1,648 1,442 4,008 3,448

2014 3,989 3,391 - - 3,989 3,391
39

2015 500 425 210 184 710 609

2016 - - 2,675 2,340 2,675 2,340

2017 - - 649 568 649 568

Total 6,849 5,822 5,182 4,534 12,031 10,356

ITEM 3. 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.

ITEM 4. MINE SAFETY DISCLOSURES.

Not Applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED 

STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY 

SECURITIES

Market Information

The Company’s common stock is listed on the NYSE MKT 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 MKT during the fiscal years ended December 31, 2012 and December 31, 2011 are set forth 

below.

High Low

For the Quarters Ending

March 31, 2012 $ 1.20 $ 0.72

June 30, 2012 $ 1.10 $ 0.68
40

September 30, 2012 $ 0.86 $ 0.68

December 31, 2012 $ 0.74 $ 0.58

March 31, 2011 $ 1.50 $ 0.60

June 30, 2011 $ 1.21 $ 0.64

September 30, 2011 $ 0.98 $ 0.63

December 31, 2011 $ 0.93 $ 0.65

Holders

As of March 15, 2013, the number of shareholders of record of the Company’s common stock 

was 283 and management believes that there are approximately 7,568 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 2012 or 

2011 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 2012, 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 2012 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 2012.

Equity Compensation Plan Information

See Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related 

Stockholder Matter” for information regarding the Company’s equity compensation plans.

ITEM 6. SELECTED FINANCIAL DATA

The following selected financial data have been derived from the Company’s financial 

statements, and should be read in conjunction with those financial statements, including the related 

footnotes. (In thousands, except per share data)
41

Years Ended December 31, 2012 2011 2010

Income Statement Data:

Revenues $ 20,557 $ 17,062 $ 13,211

Production Cost and Taxes 7,182 5,944 5,853

General and Administrative 2,613 2,324 2,294

Interest Expense 743 642 659

Net Income From Continuing Operations 4,244 4,966 1,911

Net (Loss) From Discontinued Operations (4,311) (286) (3,656)

Net Income (Loss) (67) 4,680 (1,745)

Net Income (Loss) Per Share – Continuing Operations $ 0.07 $ 0.08 $ 0.03

Net Income (Loss) Per Share – Discontinued Operations $ (0.07) $ (0.00) $ (0.06)

As of December 31, 2012 2010 2010

Balance Sheet Data:

Working Capital Surplus $ 1,615 $ 839 $ 10

Oil and Gas Properties, Net 24,700 20,206 14,157

Methane Project, Net 4,445 5,102 4,394

Assets Held For Sale 1,400 6,865 7,041

Total Assets 44,167 45,999 39,749

Long-Term Debt, Less Current Maturities 10,246 11,694 9,564

Stockholders’ Equity $ 30,134 $ 30,097 $ 25,224

No cash dividends have been declared or paid by the Company for the periods presented in the above 

tables. 
42

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

AND RESULTS OF OPERATIONS

Results of Operations

The Company reported net income from continuing operations of $4.2 million or $0.07 per share 

in 2012 compared to net income from continuing operations of $5.0 million or $0.08 per share in 2011

and net income from continuing operations of $1.9 million or $0.03 per share in 2010. The Company 

reported a net loss from discontinued operations of $(4.3) million or $(0.07) per share in 2012 compared 

to a net loss from discontinued operations of $(0.29) million or $(0.00) per share in 2011 and a net loss

from discontinued operations of $(3.7) million or $(0.06) per share in 2010. The net losses from 

discontinued operations in 2012 and 2010 were primarily due to impairments of the Company’s pipeline 

assets in the amounts of approximately $3.4 million and $3.3 million, respectively. Discontinued 

operations are net of associated taxes.

The Company realized revenues of $20.6 million in 2012 compared to $17.1 million in 2011 and 

$13.2 million in 2010. During 2012, revenues increased $3.5 million of which $3.3 million related to 

increases in oil sales volumes from 189.5 MBbl in 2011 to 226.6 MBbl in 2012. In addition, Methane 

Project revenues increased $0.5 million in 2012 primarily from electricity sales which commenced in 

January 2012. These increases were partially offset by a $(0.3) million decrease related to a $(1.21) per 

barrel decrease in the average oil price received from $88.13 per barrel in 2011 to $86.92 per barrel 

received in 2012. During 2011, revenues increased $3.9 million from 2010 of which $2.8 million related 

to a $16.01 per barrel increase in the average oil price received from $72.14 per barrel in 2010 to $88.15

per barrel in 2011 and $1.2 million related to increases in sales volumes primarily from drilling and 

polymers. These increases in 2011 were partially offset by a $(0.1) million decrease in Methane Project 

revenues.

Gas prices received for sales of gas from the Swan Creek Field averaged $3.35 per Mcf in 2012, 

$4.28 per Mcf in 2011, and $4.90 per Mcf in 2010. Oil prices received for sales of oil from the Swan 

Creek field averaged $88.29 per barrel in 2012, $87.33 per barrel in 2011, and $71.05 per barrel in 2010.

The Company’s production costs and taxes were $7.18 million in 2012, $5.94 million in 2011, 

and $5.85 million in 2010. The $1.24 million increase in 2012 was primarily due to a $0.3 million

increase in Kansas field expenses, a $0.29 million increase in Kansas property taxes, and a $0.26 million

increase in Methane Project costs.

Depreciation, depletion, and amortization was $3.4 million in 2012, $2.5 million in 2011, and 

$2.2 million in 2010. The $0.9 million increase in 2012 was primarily related to higher oil and gas 

depletion expense due to increased sales volumes and an increase in the depletion rate.

The Company’s general and administrative cost was $2.6 million in 2012 and $2.3 million in

each 2011 and 2010. The $0.3 million increase in 2012 was primarily related to a $0.26 million 

allowance recorded in 2012 for Hoactzin related receivables, a $0.1 million increase in tax preparation 

and consulting costs related to reviews of prior year tax returns, a $0.1 million increase in non-tax 

consulting cost, partially offset by a $(0.17) million decrease in bonus cost. 
43

The 2012, 2011, and 2010 cost included non-cash charges related to stock options of $0.05 

million, $0.2 million, and $0.1 million, respectively. 

Interest expense was $0.74 million in 2012, $0.64 million in 2011, and $0.66 million in 2010. 

The increase in interest expense in 2012 was due to increased borrowings from the Company’s credit 

facility with F&M Bank to supplement funding of material inventory purchases in early 2012 and to 

supplement funding of the Company’s 2012 drilling and polymer program. Although the credit facility 

balance at December 31, 2012 was $1.4 million lower than the balance at December 31, 2011, the average 

balance during 2012 was approximately $1.9 million higher than the average borrowing during 2011. 

Interest was applied against these balances at an annual rate of 5.25%.

During 2012, the Company recorded a $(0.14) million loss on derivatives. The 2012 loss on 

derivatives was comprised solely of an unrealized loss. During 2011, the Company recorded a $(0.41) 

million loss on derivatives. The 2011 loss was comprised of a $0.45 million unrealized gain, offset by 

$(0.86) million of settlement payments made to Macquarie Bank Limited (“Macquarie”) pursuant to a 

hedging agreement it entered into with Macquarie in August 2009 (see, Item 7A, “Commodity Risk”).

During 2010, the Company recorded a $0.5 million gain on derivatives. The gain was comprised of a 

$0.6 million unrealized gain partially offset by $0.1 million of settlement payments made to Macquarie.

In 2012 and in 2010, the Company recorded non-cash impairments of its pipeline assets in the 

amounts of $5.2 million ($3.4 million net of tax effect) and $5 million ($3.3 million net of tax effect), 

respectively. The pipeline assets are classified as assets held for sale in the Company’s Consolidated 

Balance Sheets. These write downs resulted from the Company’s assessment that cash flows generated 

from the pipeline were insufficient to recover the pipeline’s net book value. During 2012 and 2010 the 

Company received expressions of interest from potential purchasers of the pipeline asset which were 

significantly below the asset’s pre write down net book values. These expressions of interest indicated 

that the carrying amount of the pipeline may not be recoverable. At December 31, 2012, the Company 

was in the process of negotiating an agreement to sell the pipeline assets and the Swan Creek Field wells 

and associated equipment. Preliminary allocation of the sales value to the pipeline assets indicated a 

write down of approximately $5.2 million, before tax effect, was necessary. 

The Company recorded income tax expense on continuing operations of $2.3 million in 2012, 

$0.3 million in 2011, and an income tax expense of $0.8 million in 2010. The tax expense in 2011 was

impacted by removal of the $1.7 million valuation allowance. Had this valuation allowance not been 

removed the Company would have recorded tax expense of $2.0 million in 2011. (See Note 14.) Income 

Taxes in Notes to Consolidated Financial Statements)

Liquidity and Capital Resources

At December 31, 2012, the Company had a revolving credit facility with F&M Bank & Trust 

Company (“F&M Bank”). 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 $40 million or the 

Company’s borrowing base in effect from time to time. As of December 31, 2012, the Company’s 

borrowing base was $21.5 million. The borrowing base was reduced to $20.5 million with the March 6, 

2013 amendment to the credit agreement. The credit facility is secured by substantially all of the 

Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane 
44

Project assets. The credit facility includes certain covenants with which the Company is required to 

comply. These covenants include leverage, interest coverage, minimum liquidity, and general and 

administrative coverage ratios. During 2012 and 2011 the Company was in compliance with all 

covenants.

On March 14, 2012, the Company’s senior credit facility with F&M Bank after F&M Bank’s 

semiannual review of the Company’s then owned producing properties was amended to increase the

Company’s borrowing base from $20 million to $23 million and extend the term of the facility to January 

27, 2014. The interest rate remained the greater of prime plus 0.25% or 5.25% per annum. The 

Company’s interest rate at December 31, 2012 was 5.25%.

On September 12, 2012, the Company’s senior credit facility with F&M Bank after F&M Bank’s 

semiannual review of the Company’s then owned producing properties was amended to decrease the 

Company’s borrowing base from $23 million to $21.5 million. The term of the facility and interest rate 

remained unchanged.

On January 31, 2013, the Company’s senior credit facility with F&M Bank was amended to 

revise the “Change in Control” definition. No other changes were made to the credit facility.

On March 6, 2013, the Company’s senior credit facility with F&M Bank after F&M Bank’s 

semiannual review of the Company’s then owned producing properties was amended to reduce the

Company’s borrowing base from $21.5 million to $20.5 million and extend the term of the facility to 

January 27, 2015. The interest rate remained the greater of prime plus 0.25% or 5.25% per annum. 

The total borrowing by the Company under the facility at December 31, 2012 and December 31, 

2011 was $10.1 million and $11.5 million, respectively. The next borrowing base review will take place 

in June 2013. 

Although the Company has not been required as of the date of this Report to make any payment 

of principal to F&M Bank under the borrowing base in effect at any time, the Company can make no 

assurance that in view of the conditions in the national and world economies, including the realistic 

possibility of low commodity prices being received for the Company’s oil and gas production for 

extended periods, that F&M may in the future make a redetermination of the Company’s borrowing base 

to a point below the level of the installment or other payments to F&M in such amount and at such times

in order to reduce the principal of the Company’s outstanding borrowing to a level not in excess of the 

borrowing base as it may be redetermined.

During 2012 and 2011, the Company focused on increasing its oil production and carefully used 

its cash flow and available credit to do so. However, the Company can make no assurance that it can 

continue normal operations indefinitely or for any specific period of time in the event of extended periods

of low commodity prices, such as occurred in late 2008 and early 2009, or upon the occurrence of any 

significant downturn or losses in operations. In such event, the Company may be required to reduce costs 

of operations by various means, including not undertaking certain maintenance or reworking operations 

that may be necessary to keep some of the Company’s properties in production or to seek additional 
45

working capital by additional means such as issuance of equity including preferred stock or such other 

means as may be considered and authorized by the Company’s Board of Directors from time to time.

Net cash provided by operating activities from continuing operations was $9.3 million in 2012, 

$8.7 million in 2011, and $4.2 million in 2010. Net cash used in operating activities from discontinued

operations was $(0.29) million in 2012, $(0.24) million in 2011, and $(0.16) million in 2010. The 

increase in cash provided by operating activities from continuing operations in 2012 was primarily due to 

a $3.3 million increase related to increased sales volumes, partially offset by a $(1.3) million increase in 

production costs and taxes and a $(1.2) million decrease in changes in working capital. The increase in 

cash provided by operating activities from continuing operations in 2011 was primarily due to a $4.0 

million increase related to higher oil prices and increased sales volumes as well as $0.6 increase to 

changes in working capital. Cash flow used in working capital was $(1.1) million in 2012, $0.3 million 

was provided by working capital in 2011, and $(0.4) million was used for working capital in 2010. The 

difference in changes in working capital in 2012 as compared to 2011 was primarily related a decrease in 

accounts payable related primarily to a reduction in year-end drilling and polymer activity compared to 

2011, posting of cash collateral related to the appeal bond, and an increase in equipment and materials 

inventory. The difference in changes in working capital in 2011 as compared to 2010 was primarily 

related to an increase in accounts payable related primarily to increases in year-end drilling and polymer 

activity compared to 2010.

Net cash used in investing activities from continuing operations was $7.6 million in 2012, $10.4 

million in 2011, and $3.7 in 2010. The $2.8 million decrease in investing activities in 2012 as compared 

to 2011 was due to a $1.2 million decrease in derivative cost, receipt of a $1.0 million payment in lieu of 

tax credits related to the methane facility, a $0.35 million reduction in capital spending related to the 

Methane Facility, and a $0.2 million reduction in drilling and polymer cost. The $(6.7) million increase

in investing activities in 2011 as compared to 2010 was primarily due to a $(4.8) million increase in 

drilling and polymer spending, $(0.8) million of additional capital used to purchase and install an electric 

generator at the Methane Facility, and a $(1.2) million increase in derivative related costs. The Company 

was required to make $(0.86) million of derivative settlement payments to Macquarie as well as a $(0.37)

million payment to Cargill Incorporated (“Cargill”) to purchase a $65 floor (See Item 7A. “Commodity 

Risk” for a discussion of the agreement with Cargill).

In 2012, $(1.8) million was used in financing activities from continuing operations to pay down 

the Company’s credit facility. In 2011, $1.6 million was provided by financing activities from continuing

operations from bank funding which was used primarily to fund drilling and polymer activities during 

2011. In 2010, $0.75 million of cash was used in financing activities from continuing operations related 

primarily to the Company entering into a sweep account arrangement allowing excess cash balances to be 

used to temporarily pay down the credit facility, thereby, reducing overall interest cost. Net cash 

provided by financing activities from discontinued operations was $0.29 million in 2012, $0.24 million in 

2011, and $0.18 million in 2010. This funding was used to finance the Company’s pipeline operations.

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 
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

46

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

Revenues are recognized based on actual volumes of oil, natural gas, methane gas, and 

electricity sold to purchasers at a fixed or determinable price, when delivery has occurred and title 

has transferred, and collectability is reasonably assured. Crude oil is stored and at the time of 

delivery to the purchasers, revenues are recognized. Natural gas meters are placed at the 

customer’s location and usage is billed each month. There were no material natural gas 

imbalances at December 31, 2012. Methane gas and electricity sales meters are located at the 

tailgate of the Company’s Methane Facility and sales are billed each month.

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. in 2012, 2011, 2010, and 2009. The costs of unproved properties are excluded from

amortization until the properties are evaluated, subject to an annual assessment of whether 

impairment has occurred. The Company had $0.457 million and $0.268 million in unevaluated 

properties as of December 31, 2012 and 2011, 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). 

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

Properties
47

The capitalized costs of oil and gas properties, plus estimated future development costs relating to

proved reserves and estimated costs of plugging and abandonment, net of costs relating to proved reserves

and estimated costs of plugging and abandonment, 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, 2012 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 30-40 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. Temporary differences result 

principally from federal and state net operating loss carryforwards, differences in oil and gas property 

values resulting from a 2008 ceiling test write down, differences in pipeline values resulting from a 2010 

and a 2012 impairment, and differences in methods of reporting depreciation and amortization. 

Management routinely assesses the ability to realize our deferred tax assets and reduces such assets by a 

valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not 

be recognized.
48

At December 31, 2012, federal net operating loss carryforwards amounted to approximately 

$21.8 million which expire between 2019 and 2031. The total deferred tax asset was $9.4 million and 

$10.2 million at December 31, 2012 and 2011, respectively.

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 recovered.

 

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. 

Although management considers our valuation allowance and loss contingency as of December 

31, 2012 and 2011 adequate, material changes in these amounts may occur in the future based on tax 

audits and changes in legislation.

Recent Accounting Pronouncements

In December 2011, the FASB issued ASU No. 2011-11 Balance Sheet (Topic 210), Disclosures 

about Offsetting Assets and Liabilities. This guidance requires entities to disclose both gross information 

and net information about both instruments and transactions eligible for offset in the statement of 

financial position and instruments and transaction subject to an agreement similar to a master netting 

arrangements. In January 2013, the FASB issued ASU No. 2013-01, "Clarifying the Scope of Disclosures

about Offsetting Assets and Liabilities." The amendments in this update clarify that the scope of ASU 

2011-11 applies to derivatives accounted for in accordance with ASC 815, Derivatives and Hedging, 

including bifurcated embedded derivatives, repurchase agreements and reverse repurchase agreements, 

and securities borrowing and securities lending transactions that are either offset in accordance with ASC 

210-20-45 or ASC 815-10-45 or subject to an enforceable master netting arrangement or similar 

agreement. The amendments are effective during interim and annual periods beginning on or after 

January 1, 2013. The Company does not expect the adoption of ASU 2012-02 to impact its operating 

results, financial position or cash flows. 
49

Contractual Obligations

The following table summarizes the Company’s contractual obligations due by period as of December 31, 

2012 (in thousands): 

Contractual Obligations Total Year 1 Year 2 Year 3

Long-Term Debt Obligations1 $ 10,346 $ 100 $ 83 $ 10,163

Operating Lease Obligations 51 51 - -

Estimated Interest on Long-Term Debt Obligations 1,116 541 536 39

Total $ 11,513 $ 692 $ 619 $ 10,202

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET 

RISKS

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 

ranged from a low of $76.04 per barrel to a high of $99.59 per barrel during 2012. Gas prices realizations 

ranged from monthly low of $2.26 per Mcf to a monthly high of $6.84 per Mcf during the same period. 

In order to help mitigate commodity price risk, the Company has entered into a long term fixed 

price contract for MMC gas sales. On August 27, 2009, the Company entered into a five-year fixed price 

gas sales contract with Atmos Energy Marketing, LLC, (“AEM”) in Houston, Texas, a nonregulated unit 

of Atmos Energy Corporation (NYSE: ATO) for the sale of the methane component of landfill gas 

produced by MMC at the Carter Valley Landfill. The agreement provides for the sale of up to 600 

MMBtu per day. The contract is effective beginning with September 2009 gas production and ends July

 1 The credit facility maturity date of January 27, 2015 is based on the March 6, 2013 amendment to the credit 

agreement
50

31, 2014. The agreed contract price of over $6 per MMBtu was a premium to the then current five-year 

strip price for natural gas on the NYMEX futures market.

In addition, during 2010, 2011, and 2012, the Company participated in derivative agreements on a 

specified number of barrels of oil of its production. On July 28, 2009, the Company entered into a twoyear agreement on crude oil pricing applicable to a specified number of barrels of oil that then constituted 

approximately two-thirds of the Company’s daily production. Due to increased production levels, as well 

as a drop in the specified monthly barrels from 9,500 to 7,375 in 2011, the number of barrels subject to 

this agreement constituted less than half of the Company’s average daily production at July 31, 2011. 

This “costless collar” agreement was effective August 1, 2009 through July 31, 2011 and had a 

$60.00 per barrel floor and $81.50 per barrel cap on a volume of 9,500 barrels per month during the 

period from August 1, 2009 through December 31, 2010, and 7,375 barrels per month from January 1, 

2011 through July 31, 2011. The prices referenced in this agreement were WTI NYMEX. While the 

agreement was based on WTI NYMEX prices, the Company receives a price based on Kansas Common 

plus bonus, which results in a price approximately $7 per barrel less than current WTI NYMEX prices.

Under the “costless collar” agreement, no payment was made or received by the Company, as 

long as the settlement price was between the floor price and cap price (“within the collar”). However, if 

the settlement price was above the cap, the Company was required to pay the counterparty an amount 

equal to the excess of the settlement price over the cap times the monthly volumes hedged. If the 

settlement price was below the floor, the counterparty was required to pay the Company the deficit of the 

settlement price below the floor times the monthly volumes hedged. As of August 1 2011, the “costless 

collar” agreement had expired.

On June 27, 2011 the Company entered into an agreement with Cargill Incorporated (“Cargill”), 

for the period from August 1, 2011 through December 31, 2012. The agreement provides to the Company 

a $65 per barrel floor on a stated quantity of 10,000 barrels per month, which is approximately half of the 

Company’s current production of oil. If the average price falls below $65 per barrel, then Cargill will pay 

to the Company the difference between $65 and the lower average price for 10,000 barrels per month in 

each month during when such lower average prices occur. However, unlike the “costless collar” 

arrangement, the Company will not have a price cap on any portion of its production volumes. The cost 

of the Cargill agreement to the Company, which was paid on June 27, 2011, was $2.20 per barrel per 

month or a total of $374,000 for the entire period of the agreement. This agreement ended on December 

31, 2012.

These agreements were primarily intended to help maintain and stabilize cash flow from 

operations if lower oil prices return. 

Interest Rate Risk

At December 31, 2012, the Company had debt outstanding of approximately $10.3 million

including, as of that date, $10.1 million owed on its credit facility with F&M Bank. The interest rate on 

the credit facility is variable at a rate equal to the greater of prime rate plus 0.25%, or 5.25% per annum. 

The Company’s remaining debt of $0.2 million has fixed interest rates ranging from 3.9% to 7.25%. 
51

As a result, the Company annual interest cost in 2012 fluctuated based on short-term interest rates on 

approximately 98% of its total debt outstanding at December 31, 2012. During 2012, the Company paid

approximately $0.7 million of interest on the F&M Bank line of credit. The impact on interest expense 

and the Company’s cash flows of a 10% increase in the interest rate on the F&M Bank credit facility 

would be approximately $0.05 million assuming borrowed amounts under the credit facility remained at

the same amount owed as of December 31, 2012. The Company did not have any open derivative 

contracts relating to interest rates at December 31, 2012.

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 a prolonged 

period of low prices, may substantially adversely affect the Company’s financial position, results of 

operations and cash flows.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON 

ACCOUNTING AND FINANCIAL DISCLOSURE

During 2012, there were no changes in or disagreements with the accountants on accounting and 

financial disclosure.

As previously reported, effective September 21, 2011, the Company elected not to retain Rodefer 

Moss & Co., PLLC as its independent registered public accounting firm and engaged Hein & Associates 

LLP to be the Company’s independent registered public accounting firm. This change in accountants was 

reported in the Company’s Form 8-K filed on September 22, 2011, in the Company’s Form 10-K filed on 

March 29, 2012, and in the Company’s Proxy Statement Form Def 14A filed on April 19, 2012.

ITEM 9A. CONTROLS AND PROCEDURES

The Company’s Chief Executive Officer and Chief Financial Officer, and other members of 

management team have evaluated the effectiveness of the Company’s disclosure controls and procedures
52

(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 is 

files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the 

time periods specified in the SEC’s rules and forms.

The effectiveness of a system of disclosure controls and procedures is subject to various inherent 

limitations, including cost limitations, judgments used in decision making, assumptions about the 

likelihood of future events, the soundness of internal controls, and fraud. Due to such inherent 

limitations, there can be no assurance that any system of disclosure controls and procedures will be 

successful in preventing all errors or fraud, or in making all material information known in a timely 

manner to the appropriate levels of management.

Managements 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, 2012. 
53

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”). 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, 2012.

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.

Changes in Internal Control 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. There have been no other changes to the Company’s system 

of internal control over financial reporting during the year ended December 31, 2012 that have materially 

affected, or are reasonably likely to materially affect, the Company’s system of controls over financial 

reporting.

ITEM 9B. OTHER INFORMATION

On January 2, 2013, options to purchase 18,750 common shares at $0.64 per share were issued to 

the Company’s non-executive directors. These options fully vested upon grant date and will expire on 

January 1, 2018.

On January 31, 2013, the Company’s senior credit facility with F&M Bank was amended to 

revise the “Change in Control” definition. No other changes we made to the credit facility.

On March 1, 2013, the Company entered into an agreement with Swan Creek Partners LLC to sell 

the Company’s Swan Creek and Pipeline assets for $1.5 million. Final closing of this transaction is 

contingent upon customary due diligence as well as certain regulatory and easement holder approvals. 

On March 6, 2013, the Company’s senior credit facility with F&M Bank and Trust Company,

N.A. of Dallas, Texas (F&M Bank”) after F&M Bank’s semiannual review of the Company’s currently 

owned producing properties was amended to decrease the Company’s borrowing base from $21.5 million 

to $20.5 million and extend the term of the facility to January 27, 2015. The borrowing base remains 

subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained 

the greater of prime plus 0.25% or 5.25% per annum. The maximum line of credit of the Company under

the F&M Bank credit facility remained $40 million and the Company’s outstanding borrowing under the 

facility as of March 6, 2013 was $9.1 million.
54

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERANCE

Identification of Directors and Executive Officers

NAME POSITIONS HELD DATE OF INITIAL 

ELECTION OR 

DESIGNATION

AGE

Jeffrey R. Bailey Director;

Chief Executive 

Officer

2/28/03-8/11/04; 10/21/04

7/17/02

55

Matthew K. Behrent Director 3/27/07 42

Hughree F. Brooks Director 12/03/10 58

Peter E. Salas Director;

Chairman of the 

Board

10/8/02

10/21/04

58

Charles Patrick 

McInturff

Vice President 12/18/07 60

Michael J. Rugen Chief Financial 

Officer

9/28/09 52

Cary V. Sorensen Vice-President; 

General 

Counsel; Secretary

7/9/99 64
55

Business Experience

Directors

Jeffrey R. Bailey graduated in 1980 from New Mexico Institute of Mining and Technology with a 

B.S. degree in Geological Engineering. Upon graduation he joined Gearhart Industries as a field engineer 

working in Texas, New Mexico, Kansas, Oklahoma and Arkansas. Gearhart Industries later merged with 

Halliburton Company. In 1993, after 13 years working in various field operations and management roles 

primarily focused on reservoir evaluation, log analysis and log data acquisition he assumed a global role 

with Halliburton as a petrophysics instructor in Fort Worth, Texas. His duties were to teach Halliburton 

personnel and customers around the world log analysis and competition technology and to review 

analytical reservoir problems. In this role Mr. Bailey had the opportunity to review reservoirs in Europe, 

Latin America, Asia Pacific and the Middle East developing a special expertise in carbonate reservoirs. In 

1997, he became technical manager for Halliburton in Mexico focusing on finding engineering solutions 

to the production challenges of large carbonate reservoirs in Mexico. He joined the Company as its Chief 

Geological Engineer on March 1, 2002. The experience, qualifications, attributes, and skills gained by 

Mr. Bailey in these oil and gas exploration and production industry positions directly apply to the 

operations of the Company and lead to the conclusion that Mr. Bailey should serve as a Director of the 

Company. Mr. Bailey was elected as President of the Company on July 17, 2002 and is presently the 

Company’s Chief Executive Officer. He was elected as a Director on February 28, 2003 and served as a 

Director until August 11, 2004. He was again elected to the Company’s Board of Directors on October 

21, 2004 and has remained a Director since that time.

Matthew K. Behrent is currently is the Executive Vice President, Corporate Development of 

EDCI Holdings, Inc, a company that is currently engaged in carrying out a plan of dissolution. Before 

joining EDCI in June, 2005, Mr. Behrent was an investment banker, working as a Vice-President at 

Revolution Partners, a technology focused investment bank in Boston, from March 2004 until June 2005 

and as an associate in Credit Suisse First Boston Corporation's technology mergers and acquisitions group 

from June 2000 until January 2003. From June 1997 to May 2000, Mr. Behrent practiced law, most 

recently with Cleary, Gottlieb, Steen & Hamilton in New York, advising financial sponsors and corporate 

clients in connection with financings and mergers and acquisitions transactions. Mr. Behrent received his 

J.D. from Stanford Law School in 1997, and his B.A. in Political Science and Political Theory from 

Hampshire College in 1992. He became a Director of the Company on March 27, 2007. He is also a 

Director and Chairman of the Audit Committee of Asure Software, Inc. (Nasdaq: ASUR). 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. 

Hughree F. Brooks in 2010 co-founded Powerhouse Energy Solutions LLC, a company engaged 

in providing equipment and services to clients in renewable and alternative energy industries in the 

United States and abroad. Powerhouse is a provider of solar energy systems as well as advisory services 

to biofuel producers. Since 1998, Mr. Brooks has continuously provided consulting services in the oil 

and gas exploration industry. These services include land management, landowner representation, deal
56

structuring and financing, and expert witness services. Mr. Brooks has 35 years of experience as a land 

manager with independent and major oil companies including Amoco Production, Mitchell Energy, Ladd 

Petroleum, Phoenix Exploration and Renown Petroleum Inc. His clients own in excess of 16,000 acres in 

South Louisiana with a long history of oil and gas production. In 2002, he founded and continues to serve 

as the Executive Director of Friends Of The Farm, a Texas nonprofit. Mr. Brooks is a licensed attorney 

who received his J.D. from Loyola Law School in 1980. He received a Bachelor of Science Degree in 

1976 from Loyola University in New Orleans. The experience, qualifications, and skills of Mr. Brooks 

gained in an extensive career in the oil and gas exploration and production industry are directly related to 

the operations of the Company and lead to the conclusion that Mr. Brooks 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. Mr. Salas also served on the board of Williams Controls, Inc. 

During a portion of the last five years, Mr. Salas also served on the Board of Directors of Southwall 

Technologies, Inc. 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. 

Officers

Charles Patrick McInturff received a Bachelor of Science Degree in Civil Engineering from 

Texas A&M University in 1975. He is a Registered Professional Engineer from Texas and a member of 

the Society of Petroleum Engineers. Before joining the Company he was Vice President of Operations of 

Capco Offshore, Inc. and related companies in Houston from October 2006 until December 2007 

responsible for managing and supervising offshore operations and workovers and identification and 

evaluation of drilling and workover candidates. From 1991 to 2006, he was employed by Ryder Scott 

Company in Houston performing reservoir studies including determination of oil, gas, condensate and 

plant product reserves, enhanced recovery and oil and gas property appraisal. For most of the period 

from 1978 to 1991, he worked in various petroleum engineering positions at Union Texas Petroleum 

Corp. in Midland and Houston, Texas, and Karachi, Pakistan and was responsible for surveillance and 

engineering on primary and secondary recovery projects as well as design and field supervision of 

workovers, pressure-transient tests and completions both onshore and offshore. During that time period he 

also worked for Global Natural Resources from 1983 to 1986 as senior operations engineer responsible 

for all engineering activities. From 1981 to 1983 he was employed by Belco Petroleum performing 

reservoir engineering duties including field studies, economic evaluation, reserves estimation, and 

initiating major field studies on waterflood projects in southwestern Wyoming and West Texas. 
57

Mr. McInturff was employed by Exxon Co. USA from 1975 to 1978 primarily with the reservoir 

engineering group in Midland, Texas performing drilling engineering duties including cost estimation, 

AFE preparation, drilling programs and field supervision. He was responsible for the surveillance of 

fifteen Permian Basin oil and gas fields in west Texas using both primary and secondary recovery 

techniques. On December 18, 2007, he was appointed to serve as Vice-President of the Company.

Michael J. Rugen was named Chief Financial Officer of the Company in September 2009. He is 

a certified public accountant (Texas) with over 30 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:
58

(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 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.

(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, 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;
59

(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 

Commodity Futures Trading Commission (“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 

2012, the Company, its officers and directors and its 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 
60

of charge by writing to Cary V. Sorensen, Secretary, Tengasco, Inc., 11121 Kingston Pike, Suite E, 

Knoxville, TN 37934.

Audit Committee

In 2012, directors Hughree F. Brooks and Matthew K. Behrent, were the members of the Board’s 

Audit Committee. Mr. Behrent was the Chairman of the Committee and the Board of Directors 

determined that Mr. Behrent was an “audit committee financial expert” as defined by applicable 

Securities and Exchange Commission (“SEC”) regulations and the NYSE MKT Rules. Each of the

members of the Audit Committee met the independence and experience requirements of the NYSE MKT 

Rules, the applicable Securities Laws, and the regulations and rules promulgated by the SEC. The Audit 

Committee met each quarter and a total of five (4) times in Fiscal 2012 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 MKT 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 2012, 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 
61

April 19, 2012 for the Company’s Annual Meeting held on May 29, 2012 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. 

ITEM 11. EXECUTIVE COMPENSATION

Executive Officer Compensation

The following table sets forth a summary of all compensation awarded to, earned or paid 

to, the Company's Chief Executive Officer, Chief Financial Officer and other executive officers 

whose compensation exceeded $100,000 during fiscal years ended December 31, 2012 and 

December 31, 2011.

SUMMARY COMPENSATION TABLE

Salary Bonus 

Option 

Awards2

All Other 

Compensation3 Total

Name and Principal Position Year ($) ($) ($) ($) ($)

Jeffrey R. Bailey, 2012 189,750 - - 13,628 203,378

Chief Executive Officer 2011 189,750 59,297 - 14,278 263,325

Michael J. Rugen, 2012 150,000 - - 13,500 163,500

Chief Financial Officer 2011 150,000 37,500 - 15,759 203,259

Cary V. Sorensen, 2012 137,940 - - 9,697 147,637

General Counsel 2011 137,940 27,588 - 9,545 175,073

Charles P. McInturff, 2012 92,500 - - 17,842 110,342

Vice President 2011 92,500 18,500 - 17,024 128,024

 2 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 12 to the Consolidated Financial Statements included in 

the Company's Annual Report on Form 10-K for the year ended December 31, 2011 for information on the relevant 

valuation assumptions. 

3 The amounts in this column consist of Tengasco's matching contributions to its 401 (k) plan, personal use of 

company vehicles, and the portion of company-wide group term life insurance premiums allocable to these named

executive officers.
62

Outstanding Equity Awards at Fiscal Year-End

OPTION AWARDS

Number of securities 

underlying unexercised 

options

Number of 

securities 

underlying 

unexercised 

options

(#) (#)

Option exercise 

price 

Name exercisable unexercisable 4 ($) Option expiration date 

Jeffrey R. Bailey 127,000 

 

$ 0.44 8/29/2015

Michael J. Rugen 240,000 160,000 

 

$ 0.50 9/27/2015

Cary V. Sorensen 74,000 $ 0.44 8/29/2015

Charles P. McInturff 400,000 $ 0.57 2/1/2013

Option and Award Exercises

None in 2012. 

Employment Contracts

There are presently no 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 in Fiscal 2012 were Matthew K. 

Behrent and Hughree F. Brooks with Mr. Brooks acting as Chairman. Messrs. Behrent and Brooks meet 

the current independence standards established by the NYSE MKT Rules.

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.

 4

 Mr. Rugen's 160,000 unexercisable share options will vest at the rate of 80,000 share options per year 

on 9/27/2013, and 9/27/2014. 
63

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 MKT 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 and Stock Appreciation Rights 

(“SARs”), under the Stock Incentive Plan, including, but not limited to, determining the individuals who 

shall receive options and SARs; the times when they shall receive them; whether an option shall be an 

incentive or a non-qualified stock option; whether an SAR shall be granted separately, in tandem with or 

in addition to an option; the number of shares to be subject to each option and SAR; the term of each 

option and SAR; the date each option and SAR shall become exercisable; whether an option or SAR shall 

be exercisable in whole, in part or in installments and the terms relating to such installments; the exercise 

price of each option and the base price of each SAR; the form of payment of the exercise price; the form 

of payment by the Company upon the exercise of an SAR; whether to restrict the sale or other disposition 

of the shares of common stock acquired upon the exercise of an option or SAR; to subject the exercise of 

all or any portion of an option or SAR to the fulfillment of a contingency, and to determine whether such 

contingencies have been met; with the consent of the person receiving such option or SAR, to cancel or 

modify an option or SAR, provided such option or SAR as modified would be permitted to be granted on 

such date under the terms of the Stock Incentive Plan; and to make all other determinations necessary or 

advisable for administering the Plan.

The Compensation/Stock Option Committee met seven (7) times in Fiscal 2012. 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. 

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, however, have waived such fees due to them 

as of this date for prior meetings.
64

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 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 of the Board of Directors was authorized by the Board of Directors and approved by 

the Company’s shareholders. A copy of the Plan is posted at the Company’s website at 

www.tengasco.com. No award was made to any independent director under this plan in Fiscal 2012. 

DIRECTOR COMPENSATION FOR FISCAL 2012

Fees earned or 

paid in cash 

Option awards 

compensation 5 Total 

Name ($) ($) ($)

Matthew K. Behrent $15,000 $8,353 $23,353 

John A. Clendening $3,750 $3,586 $7,336

Hughree F. Brooks $15,000 $8,353 $23,353 

Peter E. Salas $15,000 $8,353 $23,353 

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND 

MANAGEMENT AND RELATED STOCKHOLDERS MATTERS

The following table sets forth the share holdings of those persons who own more than 5% of the 

Company's common stock as of March 15, 2013 with these computations being based upon 60,842,413 

 5 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 13 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, 2012 for information on the relevant valuation assumptions.

 As of December 31, 2012, Mr. Behrent held 143,750 unexercised options.

 As of December 31, 2012, Mr. Brooks held 43,750 unexercised options.

 As of December 31, 2012, Mr. Salas held 143,750 unexercised options.
65

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 15, 2013.

FIVE PERCENT STOCKHOLDERS 6

Name and Address Title

Number of Shares 

Beneficially Owned Percent of Class

SSB Ventures LLC

11121 Kingston Pike, Suite E

Knoxville, TN 37934

Stockholder 16,376,321 26.9%

Dolphin Offshore Partners, L.P.

c/o Dolphin Mgmt. Services, Inc.

P.O. Box 16867

Fernandina Beach, FL 32034

Stockholder 5,381,171 8.8%

SECURITY OWNERSHIP OF DIRECTORS AND OFFICERS

Name and Address Title

Number of Shares

Beneficially Owned 7

Percent of 

Class8

Jeffrey R. Bailey Director;

Chief Executive

Officer

876,4949 1.4%

 6 Unless otherwise stated, all shares of Common Stock are directly held with sole voting and dispositive power.

7 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 15, 2013. 8 Calculated pursuant to Rule 13d-3(d) under the Securities Exchange Act of 1934 based upon 60,842,413 shares of common 

stock being outstanding as of March 15, 2013. Shares not outstanding that are subject to options or warrants exercisable by 

the holder thereof within 60 days of March 15, 2013 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.

9 Consists of 249,494 shares held directly and vested, fully exercisable options to purchase 127,000 shares and 500,000 shares 

held directly by SSB Ventures LLC over which he has voting control. Jeffrey R. Bailey is a member of SSB Ventures LLC.
66

Matthew K. Behrent Director 183,00010 Less than 1%

Hughree F. Brooks Director 50,00011 Less than 1%

Michael J. Rugen Chief Financial

Officer

240,00012 Less than 1%

Peter E. Salas Director;

Chairman of the Board 

21,207,49213 34.9%

Cary V. Sorensen Vice President;

General Counsel;

Secretary

310,22614 Less than 1%

All Officers and Director-Nominees As a 

group

22,867,21215 37.6%

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, 2012.

 10 Consists of 33,000 shares held directly and vested, fully exercisable options to purchase 150,000 shares.

11 Consists of vested, fully exercisable options to purchase 50,000 shares. 12 Consists of vested, fully exercisable options to purchase 240,000 shares 13 Consists of directly, vested, fully exercisable options to purchase 150,000 shares and 15,676,321 held directly by SSB 

Ventures LLC over which he has voting control and 5,381,171 shares held directly by Dolphin Offshore Partners, L.P. 

(“Dolphin”). Peter E. Salas is a member of SSB Ventures LLC and is the sole shareholder of and controlling person of Dolphin 

Management, Inc. which is the general partner of Dolphin. 

14 Consists of 36,226 shares held directly and vested, fully exercisable options to purchase 74,000 shares and 200,000 shares 

held directly by SSB Ventures LLC over which he has voting control. Cary V. Sorensen is a member of SSB Ventures LLC.

15 Consists of 318,720 shares held directly by management, 16,376,321 held by SSV Ventures LLC, 5,381,171 shares held by 

Dolphin and vested, fully exercisable options to purchase 791,000 shares.
67

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 

approved by security holders16

1,372,250 $0.61 2,202,118

Equity compensation plans not 

approved by security holders

- - -

Total 1,372,250 $0.61 2,202,118

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND 

DIRECTOR INDEPENDENCE

Certain Transactions

There have been no material transactions, series of similar transactions or currently proposed 

transactions during Fiscal 2011 and 2012, 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.

Director Independence

The Rules of the NYSE MKT (the “NYSE MKT Rules”) require that issuers, such as the 

Company, which are 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 MKT 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 

 16 Refers to Tengasco, Inc. Stock Incentive Plan (the “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 Plan provides for the grant to employees of the Company of “Incentive Stock Options” within the meaning of Section 

422 of the Internal Revenue Code of 1986, as amended, nonqualified stock options to outside Directors and consultants the Company and stock 

appreciation rights. The Plan was approved by the Company’s shareholders on June 26, 2001. Initially, the Plan provided for the issuance of a 

maximum of 1,000,000 shares of the Company’s $.001 par value common stock. Thereafter, the Company’s Board of Directors adopted and the 

shareholders approved amendments to the Plan to increase the aggregate number of shares that may be issued under the Plan to 7,000,000 shares. 

The most recent 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 10 years was approved by the Company Board of Directors on February 1, 2008 and approved by the Company’s shareholders at 

the Annual Meeting of Stockholders held June 2, 2008.
68

qualify as independent under the criteria set forth in Rule 10 A-3 of the Securities Exchange Act of 1934 

and NYSE MKT Rule 803(b)(2)(c). The Board of Directors has determined that three of the four 

director-nominees, Matthew K. Behrent, Hughree F. Brooks, and Peter E. Salas, are independent as 

defined by the NYSE MKT Rules, and that Matthew K. Behrent and Hughree F. Brooks 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 each of these nominees does not have 

any relationship which would interfere with the exercise of his independent judgment in carrying out his 

responsibilities as a director. In reaching its determination, the Board of Directors reviewed certain 

categorical independence standards to provide assistance in the determination of director independence. 

The categorical standards are set forth below and provide that a director will not qualify as an 

independent director under the NYSE MKT 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 17 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 nondiscretionary 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.

 17 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).
69

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 person18 of the Company or any of its subsidiaries.

 The Director did not participate 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.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Audit and Non-Audit Fees 

The following table presents the fees for professional audit services rendered by the 

Company’s current independent accountants, Hein & Associates (“Hein”), 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 year ended December 31, 2012, the audit of the Company’s annual consolidated 

financial statements for the fiscal year ended December 31, 2011 and fees associated with services 

performed for the quarter ended September 30, 2011, and the fees for professional audit services rendered 

by the Company’s previous independent accountants, Rodefer Moss & Co, PLLC (“Rodefer Moss”), for 

fees associated with services performed for the quarters ended March 31, 2011 and June 30, 2011, and 

fees for other services rendered by each of them during each of those periods: 

 18 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.
70

AUDIT AND NON-AUDIT FEES

2012 2011

Audit Fees $ 132,375 $ 127,668

Audit-Related Fees - -

-

Tax Fees -

 

- 

All Other Fees -

 

- 

Total Fees $ 132,375 $ 127,668

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 registration statements 

and other offering memoranda.

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 services for 2012 and 2011 were performed by the full-time, permanent 

employees of Hein and Rodefer Moss.
71

All of the 2012 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 Hein were compatible with maintaining its independence and 

concluded they were.

PART IV.

ITEM 15. EXHIBITS AND FINANCIAL STATEMENTS SCHEDULES

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

1. Financial Statements:

Consolidated Balance Sheets

Consolidated Statements of Operations

Consolidated Statements of Stockholders Equity

Consolidated Statements of Cash Flows

Notes to Consolidated Financial Statements

2. Financial Schedules:

Schedules have been omitted because the information required to be set forth therein is 

not applicable or is included in the Consolidated Financial Statements or notes thereto.

3. Exhibits.
72

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

Exhibit Index

Exhibit Number Description

3.1 Delaware Certificate of Incorporation (Incorporated by reference to Exhibit B to 

registrant’s Definitive Proxy Statement pursuant to Schedule 14a filed May 2, 2011). 

3.2 Bylaws (Incorporated by reference to Exhibit B to registrant’s Definitive Proxy 

Statement filed May 2, 2011). 

3.3 Agreement and Plan of Merger of Tengasco, Inc. (a Tennessee corporation with and 

into Tengasco, Inc., a Delaware corporation dated as of April 15, 2011 (Incorporated 

by reference to Exhibit B to registrant’s Definitive Proxy Statement pursuant to 

Schedule 14a filed May 2, 2011). 

4.1 Form of Rights Certificate Incorporated by reference to registrant’s statement on 

Form S-1 filed February 13, 2004 Registration File No. 333-109784 (the “Form S1")

10.1 Natural Gas Sales Agreement dated November 18, 1999 between Tengasco, Inc. and 

Eastman Chemical Company (Incorporated by reference to Exhibit 10.10 to the 

registrant’s current report on Form 8-K filed November 23, 1999)

10.2 Amendment Agreement between Eastman Chemical Company and Tengasco, Inc. 

dated March 27, 2000 (Incorporated by reference to Exhibit 10.14 to the registrant’s 

1999 Form 10-KSB)

10.3 Tengasco, Inc. Incentive Stock Plan (Incorporated by reference to Exhibit 4.1 to the 

registrant’s registration statement on Form S-8 filed October 26, 2000)

10.4 Amendment to the Tengasco, Inc. Stock Incentive Plan dated May 19, 2005 

(Incorporated by reference to Exhibit 4.2 to the registrant’s registration statement on 

Form S-8 filed June 3, 2005)
73

10.5 Loan and Security Agreement dated as of June 29, 2006 between Tengasco, Inc. and 

Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.1 to the registrant’s 

Current Report on Form 8-K dated June 29, 2006)

10.6 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”])..

10.7 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).

10.8 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).

10.9 Assignment of Notes and Liens Dated December 17, 2007 between Citibank, N.A., 

as Assignor, Sovereign Bank, as Assignee and Tengasco, Inc., Tengasco Land & 

Mineral Corporation and Tengasco Pipeline Corporation as Debtors (Incorporated 

by reference to Exhibit 10.18 to the 2007 Form 10-K).

10.10 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). 

10.11 Amendment to the Tengasco, Inc. Stock Incentive Plan dated February 1, 2008, 2008 

(Incorporated by reference to Exhibit 4.1 to the registrant’s registration statement on 

Form S-8 filed June 3, 2008)

10.12 Assignment of Leases from Black Diamond Oil, Inc. to Tengasco, Inc. (Incorporated 

by reference to Exhibit 10.1 to the registrant’s Quarterly Report on Form 10-Q for 

the quarter ended June 30, 2008 filed on August 11, 2008).

10.13 Energy Option Transaction Confirmation Agreement (Put) between Tengasco, Inc. 

and Macquarie Bank Limited dated September 17, 2009 (Incorporated by reference 

to Exhibit 10.13 to the registrant’s Annual Report on Form 10-K for the year ended 

December 31, 2009 filed on March 31, 2010).

10.14 Energy Option Transaction Confirmation Agreement (Call) Amendment between 

Tengasco, Inc. and Macquarie Bank Limited dated September 17, 2009

(Incorporated by reference to Exhibit 10.14 to the registrant’s Annual Report on 

Form 10-K for the year ended December 31, 2009 filed on March 31, 2010).

10.15 Assignment of Credit Facility to F&M Bank and Trust Company (Incorporated by 

reference to Exhibit 10.15 to the registrant’s Annual Report on Form 10-K for the 

year ended December 31, 2010 filed on March 31, 2011).
74

10.16 Ninth Amendment to Loan and Security Agreement dated February 22, 2011 

between Tengasco, Inc. as borrower and F&M Bank & Trust Company as Lender 

(incorporated by reference to Exhibit 9.01to the registrant’s Current Report on Form 

8-K filed on February 25, 2011). 

10.17

10.18*

10.19*

10.20*

Tenth Amendment to Loan and Security Agreement dated March 14, 2012 between 

Tengasco, Inc. as borrower and F&M Bank & Trust Company as Lender

Eleventh Amendment to Loan and Security Agreement dated September 12, 2012 

between Tengasco, Inc. as borrower and F&M Bank & Trust Company as Lender

Twelfth Amendment to Loan and Security Agreement dated January 29, 2013 

between Tengasco, Inc. as borrower and F&M Bank & Trust Company as Lender

Thirteenth Amendment to Loan and Security Agreement dated March 6, 2013 

between Tengasco, Inc. as borrower and F&M Bank & Trust Company as Lender

14 Code of Ethics (Incorporated by reference to Exhibit 14 to the registrant’s Annual 

Report on Form 10-K filed March 30, 2004) 

21 List of subsidiaries (Incorporated by reference to Exhibit 21 to the 2007 Form 10-K).

23.1* Consent of LaRoche Petroleum Consultants, Ltd.

23.2* Consent of Rodefer Moss & Co., PLLC

31.1* Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14

31.2* Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a)

32.1* Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as 

adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

32.2* Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as 

adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99.1* Report of LaRoche Petroleum Consultants, Ltd. has been added to the filing for the 

year ended December, 31, 2012

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* XBRLTaxonomy Presentation Linkbase Document

* Exhibit filed with this Report
75

Signatures

Pursuant to the requirements of Section 13 or 15 (d) of the Securities and Exchange Act of 1934, 

the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto 

duly authorized.

Dated: March 29, 2012

Tengasco, Inc.

(Registrant)

By: s/ Jeffrey R. Bailey

Jeffrey R. Bailey, 

Chief Executive Officer

By: s/ Michael J. Rugen

Michael J. Rugen, 

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/ Jeffrey R. Bailey

Jeffrey R. Bailey

Director; Chief Executive Officer March 29, 2013

s/ Matthew K. Behrent

Matthew K. Behrent

Director March 29, 2013

s/ Peter E. Salas

Peter E. Salas

Director March 29, 2013

s/ Hughree F. Brooks

Hughree F. Brooks

Director March 29, 2013

s/ Michael J. Rugen

Michael J. Rugen

Principal and Financial Accounting Officer March 29, 2013
Tengasco, Inc. 

and Subsidiaries

Consolidated Financial Statements

Years Ended December 31, 2012, 2011, and 2010
Report of Independent Registered Public Accounting Firms

F-4, F-5

Consolidated Financial Statements

 Consolidated Balance Sheets F-6

 Consolidated Statements of Operations F-8

Consolidated Statements of Stockholders’ Equity F-9

 Consolidated Statements of Cash Flows F-10

Notes to Consolidated Financial Statements F-12
F-4

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders

Tengasco, Inc.

We have audited the accompanying consolidated balance sheets of Tengasco, Inc. and subsidiaries as of 

December 31, 2012 and 2011, and the related consolidated statements of operation, stockholders’ equity, 

and cash flows for each of the two years in the period ended December 31, 2012. These consolidated 

financial statements are the responsibility of the Company’s management. Our responsibility is to express 

an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight 

Board (United States). Those standards require that we plan and perform the audit to obtain reasonable 

assurance about whether the financial statements are free of material misstatement. The Company is not 

required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. 

Our audits included consideration of internal control over financial reporting as a basis for designing audit 

procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and 

disclosures in the financial statements, assessing the accounting principles used and significant estimates 

made by management, as well as evaluating the overall financial statement presentation. We believe that 

our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material 

respects, the financial position of Tengasco, Inc. and subsidiaries as of December 31, 2012 and 2011, and 

the results of their operations and their cash flows for each of the two years in the period ended December 

31, 2012, in conformity with U.S. generally accepted accounting principles. 

s/Hein & Associates LLP

Houston, Texas

March 29, 2013
F-5

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Director’s and

Stockholder’s of Tengasco, Inc.

We have audited the accompanying consolidated balance sheets of Tengasco, Inc. (the “Company”) as of December 

31, 2010 and 2009, and the related consolidated statements of operations, stockholders’ equity and cash flows for 

each of the years in the three-year period ended December 31, 2010. The Company’s management is responsible for 

these consolidated financial statements. Our responsibility is to express an opinion on these consolidated financial 

statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board 

(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about 

whether the financial statements are free of material misstatement. The company was not required for 2010 to have, 

nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included 

consideration of internal control over financial reporting as a basis for designing audit procedures that are 

appropriate in the circumstances, 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. An audit also 

includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 

assessing the accounting principles used and significant estimates made by management, as well as evaluating the 

overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the 

financial position of Tengasco, Inc. as of December 31, 2010 and 2009, and the results of its operations and its cash 

flows for each of the years in the three year period ended December 31, 2010 in conformity with accounting 

principles generally accepted in the United States of America.

s/ Rodefer Moss & Co., PLLC

Knoxville, Tennessee

March 31, 2011 
F-6

Tengasco, Inc. and Subsidiaries

Consolidated Balance Sheets

(In thousands, except per share and share data)

December 31,

2012 2011

Assets

Current

 Cash and cash equivalents $ 31 $ 68

 Accounts receivable 1,608 1,579

 Accounts receivable-related party, less allowance for doubtful 68 265

 accounts of $257 and $0

 Inventory 1,402 823

 Deferred tax asset-current - 164

 Commodity derivative asset-current - 142

 Other current assets 194 79

 Total current assets 3,303 3,120

 Restricted cash 507 121

 Loan fees, net 57 82

 Oil and gas properties, net (full cost accounting method) 24,700 20,206

 Methane project, net 4,445 5,102

 Other property and equipment, net 321 426

 Assets held for sale 1,400 6,865

 Deferred tax asset-noncurrent 9,434 10,077

 Total assets $ 44,167 $ 45,999

See accompanying Notes to Consolidated Financial Statements
F-7

Tengasco, Inc. and Subsidiaries

Consolidated Balance Sheets 

(In thousands, except per share and share data)

December 31,

2012 2011

Liabilities and Stockholders’ Equity

Current liabilities

 Accounts payable-trade $ 648 $ 1,203

 Accounts payable other 325 265

 Accrued liabilities 615 710

 Current maturities of long-term debt 100 103

 Total current liabilities 1,688 2,281

 Asset retirement obligation 2,099 1,927

 Long term debt, less current maturities 10,246 11,694

 Total liabilities 14,033 15,902

Commitments and contingencies (Note 9)

Stockholders’ equity

 Common stock, $.001 par value: authorized 100,000,000 Shares; 

 60,842,413 and 60,737,413 shares issued and outstanding 61 61

 Additional paid in capital 55,699 55,595

 Accumulated deficit (25,626) (25,559)

 Total stockholders’ equity 30,134 30,097

Total liabilities and stockholders’ equity $ 44,167 $ 45,999

See accompanying Notes to Consolidated Financial Statements
F-8

Tengasco, Inc. and Subsidiaries

Consolidated Statements of Operations 

(In thousands, except per share and share data)

Year ended December 31,

2012 2011 2010

Revenues $ 20,557 $ 17,062 $ 13,211

Cost and expenses

 Production costs and taxes 7,182 5,944 5,853

 Depreciation, depletion, and amortization 3,403 2,527 2,206

 General and administrative 2,613 2,324 2,294

 Total cost and expenses 13,198 10,795 10,353

Income from operations 7,359 6,267 2,858

Other income (expense)

 Interest expense (743) (642) (659)

 Gain (loss) on derivatives (142) (407) 492

 Gain (loss) on sale of assets 83 37 15

 Total other income (expense) (802) (1,012) (152)

Income from continuing operations before 

income tax

6,557 5,255 2,706

 Deferred income tax expense (2,226) (245) (795)

 Current income tax expense (87) (44)

Income from continuing operations $ 4,244 $ 4,966 $ 1,911

(Loss) from discontinued operations, net of 

income tax benefit

$ (4,311) $ (286) $ (3,656)

Net income (loss) $ (67) $ 4,680 $ (1,745)

Net income (loss) per share - Basic

 Net income from continuing operations $ 0.07 $ 0.08 $ 0.03

 Net (loss) from discontinued operations $ (0.07) $ (0.00) $ (0.06)

Net income (loss) per share - Diluted

 Net income from continuing operations $ 0.07 $ 0.08 $ 0.03

 Net (loss) from discontinued operations $ (0.07) $ (0.00) $ (0.06)

Shares used in computing earnings per share

 Basic 60,778,356 60,701,660 60,415,859

 Diluted 61,154,631 61,088,983 60,656,992

See accompanying Notes to Consolidated Financial Statements
F-9

Tengasco, Inc. and Subsidiaries

Consolidated Statements of Stockholders’ Equity 

(In thousands, except per share and share data)

Common Stock Paid-in

Capital

Accumulated

Deficit Total

Shares Amount

 Balance, December 31, 2009 59,760,661 $ 60 $ 55,277 $ (28,494) $ 26,843

 Net loss - - - (1,745) (1,745)

 Options and compensation expense - - 111 - 111

 Common stock issued for exercise of options 926,752 1 14 - 15

 Balance, December 31, 2010 60,687,413 $ 61 $ 55,402 $ (30,239) $ 25,224

 Net income - - - 4,680 4,680

 Options and compensation expense - - 165 - 165

 Common stock issued for exercise of options 50,000 - 28 - 28

 Balance, December 31, 2011 60,737,413 $ 61 $ 55,595 $ (25,559) $ 30,097

 Net income - - - (67) (67)

 Options and compensation expense - - 52 - 52

 Common stock issued for exercise of options 105,000 - 52 - 52

 Balance, December 31, 2012 60,842,413 $ 61 $ 55,699 $ (25,626) $ 30,134

See accompanying Notes to Consolidated Financial Statements
F-10

Tengasco, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

(In thousands)

Year Ended December 31,

2012 2011 2010

Operating activities

Net income from continuing operations $ 4,244 $ 4,966 $1,911

Adjustments to reconcile net income (loss) to net cash

 provided by operating activities

 Depreciation, depletion, and amortization 3,403 2,527 2,206

 Amortization of loan fees-interest expenses 55 77 97

 Accretion of discount on asset retirement obligation 132 96 112

 Gain on sale of vehicles/equipment (83) (37) (15)

 Compensation and services paid in stock options 52 165 111

 Deferred income tax expense (benefit) 2,226 245 795

 (Gain) loss on derivatives 142 407 (626)

 Allowance for doubtful accounts 257 - -

Changes in assets and liabilities

 Restricted cash (386) - -

 Accounts receivable (29) (62) (369)

 Accounts receivable-related party (60) 728 (993)

 Inventory and other assets (579) (246) 4

 Other assets (115) (37) (22)

 Accounts payable-trade 136 653 (191)

 Accounts payable- other 60 (728) 993

 Accrued liabilities (95) 139 268

 Settlement on asset retirement obligations (52) (165) (75)

Net cash provided by operating activities – continuing operations 9,308 8,728 4,206

Net cash (used in) in operating activities – discontinued operations (265) (237) (162)

Net cash provided by operating activities 9,043 8,491 4,044

Investing activities

 Additions to oil and gas properties (8,116) (8,315) (3,533)

 Proceeds from sale of oil and gas properties - 36 -

 Additions to Methane Project (464) (811) (69)

 Section 1603 refund – methane facilities 1,000 - -

 Additions to other property & equipment (15) (48) (134)

 Proceeds from sale of other property & equipment 22 - -

 Derivative costs and settlements - (1,236) -

Net cash (used in) investing activities – continuing operations (7,573) (10,374) (3,736)

Net cash (used in) investing activities – discontinued operations - - (22)

Net cash (used in) investing activities (7,573) (10,374) (3,758)

Financing activities

 Proceeds from exercise of options/warrants 52 28 15

 Proceeds from borrowings 18,339 17,912 3,655

 Repayment of borrowings (20,133) (16,307) (4,371)

 Loan fees (30) (60) (50)

Net cash provided by (used in) financing activities – continuing 

operations

(1,772) 1,573 (751)

Net cash provided by financing activities – discontinued operations 265 237 184

Net cash provided by (used in) financing activities (1,507) 1,810 (567)
F-11

Net change in cash and cash equivalents – continuing operations (37) (73) (281)

Cash and cash equivalents, beginning of period 68 141 422

Cash and cash equivalents, end of period $ 31 $ 68 $ 141

Supplemental cash flow information:

 Cash interest payments $ 688 $ 565 $ 562

 Cash paid for taxes $ 67 $ 8 $ - 

Supplemental non-cash investing and financing activities:

 Financed Company vehicles $ 175 $ 262 $ 44

 Asset retirement obligations incurred $ 92 $ 559 $ 950

 Accrued capital expenditures included in accounts payable $ - $ 691 $ -

See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-12

1. Description of Business and Significant Accounting Policies

Tengasco, Inc. is a Delaware corporation (“Tengasco” or the “Company”). 

The Company is in the business of exploration and production of oil and natural gas. The 

Company’s primary area of oil exploration and production is in Kansas. The Company’s primary area of 

natural gas exploration and production is the Swan Creek Field in Tennessee.

The Company’s wholly-owned subsidiary, Tengasco Pipeline Corporation (“TPC”), owns and 

operates a 65 mile intrastate pipeline which it constructed to transport natural gas from the Company’s 

Swan Creek Field to customers in Kingsport, Tennessee.

The Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) 

operates treatment and delivery facilities using the latest developments in available treatment technologies 

for the extraction of methane gas from nonconventional sources for delivery through the nations existing 

natural gas pipeline system, including the Company’s TPC pipeline system in Tennessee for eventual sale 

to natural gas customers.

Principles of Consolidation

The accompanying consolidated financial statements are presented in accordance with accepted 

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, stockbased 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

Revenues are recognized based on actual volumes of oil, natural gas, methane gas, and electricity

sold to purchasers at a fixed or determinable price, when delivery has occurred and title has transferred, 

and collectability is reasonably assured. Crude oil is stored and at the time of delivery to the 
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-13

purchasers, revenues are recognized. Natural gas meters are placed at the customer’s location and usage 

is billed each month. There were no material natural gas imbalances at December 31, 2012 or 2011. 

Methane gas and electricity sales meters are located at the tailgate of the Company’s Methane Facility and 

sales are billed each month. 

Cash and Cash Equivalents

Cash and cash equivalents include temporary cash investments with a maturity of ninety days or 

less at date of purchase. The Company has elected to enter into a sweep account arrangement allowing 

excess cash balances to be used to temporarily pay down the credit facility, thereby, reducing overall 

interest cost.

Restricted Cash

As security required by Tennessee oil and gas regulations, the Company placed $120,500 in a 

Certificate of Deposit to cover future asset retirement obligations for the Company’s Tennessee wells. At 

December 31, 2012 and 2011, this amount was recorded in the Consolidated Balance Sheets under 

“Restricted cash”.

In addition, during the 4th quarter of 2012, the Company placed $386,000 as collateral for a bond 

to appeal a civil penalty related to issuance of an “Incidence of Non-Compliance” by the Bureau of Ocean 

Energy Management (“BOEM”) concerning one of the Hoactzin wells operated by the Company pursuant 

to the Management Agreement. At December 31, 2012, this amount was recorded in the Consolidated 

Balance Sheets under “Restricted cash”. (See Note 9. Commitments and Contingencies)

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 per barrel cost which includes production 

costs and taxes, allocated general and administrative costs, and allocated interest cost. The market 

component is calculated using the average December 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, 2012 and 2011, inventory consisted of the following (in thousands): 

December 31,

2012 2011

Oil – carried at cost $ 650 $ 679

Equipment and materials – carried at cost 752 144

Total inventory $ 1,402 $ 823
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-14

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. in 2012, 2011, 2010, and 2009. The costs of unproved properties are 

excluded from amortization until the properties are evaluated, subject to an annual assessment of whether 

impairment has occurred. The Company had $0.457 million and $0.268 million in unevaluated properties 

as of December 31, 2012 and 2011, 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). (See Note. 4 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 a “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.
F-15

Pipeline Facilities 

The pipeline was placed into service in 2001. The pipeline is being depreciated over its 

estimated useful life of 30 years. The Company reviews the carrying value of the pipeline for 

impairment whenever events and circumstances indicate that the carrying value of an asset may 

not be recoverable from the estimated future cash flows expected to result from its use and 

eventual disposition. In cases where undiscounted expected future cash flows are less than the 

carrying value, an impairment loss is recognized equal to an amount by which the carrying value 

exceeds the fair value of assets. The factors considered by management in performing this 

assessment include current operating results, trends, and prospects, as well as the effects of 

obsolescence, demand, competition, and other economic factors. During 2010 and 2012, there 

were indicators the pipeline may be impaired and the Company performed an assessment of the 

carrying value as of December 31, 2010 and December 31, 2012 based on expected future cash 

flows. The assessments resulted in the Company recording an impairment of approximately $5.0 

million or $3.3 million net of tax for the year ended December 31, 2010 and $5.2 million or $3.4

million net of tax for the year ended December 31, 2012. At December 31, 2011 management 

determined there were no indicators of impairment, therefore, there is no impairment charge for 

the year ended December 31, 2011. The Company’s pipeline facilities are classified as an asset 

held for sale the related operations are classified as discontinued operations in the accompanying 

financial statements. (See Note 7 . Assets Held for Sale and Discontinued Operations)

Manufactured Methane Facilities

The methane facilities were placed into service on April 1, 2009. The methane facilities 

are being depreciated over an estimated useful life of 32 years and 9 months beginning at the time 

it was placed in service. This useful life is based on the estimated landfill closure date of 

December 2041. (See Note 5. Methane Project)

In June 2012, the Company received a payment in the amount of approximately $1.0 

million from the United States Department of the Treasury for a cash payment in lieu of tax 

credits relating to the methane facilities. The payment to the Company was authorized under 

Section 1603 of Division B of the American Recovery and Reinvestment Act of 2009. The grant 

amount was calculated pursuant to provisions applicable to a “landfill gas project,” defined in this 

statute as a project generating electricity from landfill gas. The Company may not take 

investment tax credits for this facility as a result of accepting the cash payment, and is subject to 

annual reporting of the status of the project and recapture of all or a portion of the payment in the 

event the project were to be assigned to an ineligible nonprofit or governmental entity, during the 

five year period following the date of the award. The Company does not anticipate that the 

payment will be subject to recapture. Pursuant to the terms of the implementing federal 

regulations, the cash payment awarded is not treated as taxable income, but does reduce the 

taxable basis of the project by half of the grant amount. However, the book carrying amount of 

the property was reduced by the full amount of the payment.
F-16

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. (See Note 6. Other Property and Equipment)

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 $0.05 million in 2012, $0.2 million in 2011 and 

$0.1 million in 2010.

Accounts Receivable 

Accounts receivable consist of uncollateralized joint interest owner obligations due 

within 30 days of the invoice date, uncollateralized accrued revenues due under normal trade 

terms, generally requiring payment within 30 days of production, and other miscellaneous 

receivables. No interest is charged on past-due balances. Payments made on accounts receivable 

are applied to the earliest unpaid items. We review accounts receivable periodically and reduce 

the carrying amount by a valuation allowance that reflects our best estimate of the amount that 

may not be collectible. No such allowance was considered necessary at December 31, 2012 or 

2011. At December 31, 2012 and 2011, accounts receivable consisted of the following (in 

thousands):

December 31,

2012 2011

Revenue $ 1,517 $ 1,412

Joint interest 65 112

Other 26 55

Total accounts receivable $ 1,608 $ 1,579

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. Management routinely assesses the ability to realize our deferred tax assets and reduces 

such assets by a valuation allowance if it is more likely than not that some portion or all of the 

deferred tax assets will not be recognized.
F-17

At December 31, 2012, federal net operating loss carryforwards amounted to 

approximately $21.8 million which expire between 2019 and 2031. The total deferred tax asset 

was $9.4 million and $10.2 million at December 31, 2012 and 2011, respectively.

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 recovered.

 

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. 

Although management considers our valuation allowance and loss contingency as of 

December 31, 2012 and 2011 adequate, material changes in these amounts may occur in the 

future based on tax audits and changes in legislation.

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. 

We have never experienced any losses related to these balances. 

The Company’s primary business activities include oil and gas sales to a limited number 

of customers in the states of Kansas and Tennessee. The related trade receivables subject the 

Company to a concentration of credit risk.

The Company sells a majority of its crude oil primarily to one customer in Tennessee and 

two customers in Kansas. Additionally, the Company presently sells all gas from the Swan Creek 

Field and the Methane Facility to one customer. In addition, the Company sells the electricity 

generated at the Methane Facility to a local utility. 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 projected results of operations.
F-18

Revenue from the top three purchasers accounted for 84.0%, 14.3%, and 2.2% of total 

revenues for year ended December 31, 2012. Revenue from the top three purchasers accounted 

for 83.5%, 13.9% and 1.9% of total revenues for the year ended December 31, 2011. Revenue 

from the top three purchasers accounted for 80.0%, 16.6% and 2.3% of total revenues for the year 

ended December 31, 2010.

Earnings per Common Share

We report 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 our basic and diluted earnings per share, (in thousands 

except for share and per share amounts): 

For the years ended December 31,

2012 2011 2010

Income (numerator):

 Net income from continuing operations $ 4,244 $ 4,966 $ 1,911

 Net loss from discontinued operations $ (4,311) $ (286) $ (3,656)

Weighted average shares (denominator):

 Weighted average shares - basic 60,778,356 60,701,660 60,415,859

 Dilution effect of share-based compensation, 

 treasury method 376,275 387,323 241,133

 Weighted average shares - dilutive 61,154,631 61,088,983 60,656,992

Earnings (loss) per share – Basic and Dilutive:

 Continuing Operations $ 0.07 $ 0.08 $ 0.03

 Discontinued Operations $ (0.07) $ (0.00) $ (0.06)

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, 2012 and 2011. (See Note 10. Fair Value Measurements)

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. (See Note 11.

Derivatives)
F-19

Reclassifications

Certain prior year amounts have been reclassified to conform to current year presentation 

with no effect on net income. 

Discontinued Operations

During 2012, the Company committed to a plan to sell the Swan Creek and Pipeline 

assets. At December 31, 2012, the Company was in the process of negotiating this sale and on 

March 1, 2013, the Company entered into an agreement to sell the Company’s Swan Creek and 

Pipeline assets for $1.5 million. Final closing of this transaction is contingent upon customary 

due diligence as well as certain regulatory and easement holder approvals. The Company has 

elected to classify the Pipeline assets as “Non-current assets held for sale” in the Consolidated 

Balance Sheets for the years ended December 31, 2012 and 2011. The related results of 

operations have been classified as “Net loss from discontinued operations in the Consolidated 

Statements of Operations for the years ended December 31, 2012, 2011, and 2010. The related 

cash flows have been classified as “Net cash (used in) operating activities – discontinued 

operations”, “Net cash (used in) investing activities – discontinued operations”, and Net cash 

(used in) financing activities – discontinued operations”. As the Swan Creek assets represent 

only a small portion of the Company’s full cost pool, these assets will remain in oil and gas 

properties and related operations and will continue to be classified in continuing operations. 

Unless otherwise indicated, the information in these notes relate to the Company’s continuing 

operations. Information related to the assets held for sale and discontinued operations is included 

in “Note 7. Assets Held for Sale and Discontinued Operations”.

2. Recent Accounting Pronouncements

In December 2011, the FASB issued ASU No. 2011-11 Balance Sheet (Topic 210), 

Disclosures about Offsetting Assets and Liabilities. This guidance requires entities to disclose 

both gross information and net information about both instruments and transactions eligible for 

offset in the statement of financial position and instruments and transactions subject to an 

agreement similar to master netting arrangements. In January 2013, the FASB issued ASU No. 

2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities." The 

amendments in this update clarify that the scope of ASU 2011-11 applies to derivatives accounted 

for in accordance with ASC 815, Derivatives and Hedging, including bifurcated embedded 

derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing 

and securities lending transactions that are either offset in accordance with ASC 210-20-45 or 

ASC 815-10-45 or subject to an enforceable master netting arrangement or similar agreement. 

The amendments are effective during interim and annual periods beginning on or after January 1, 

2013. The Company does not expect the adoption of ASU 2012-02 to impact its operating results, 

financial position or cash flows. 
F-20

3. Related Party Transactions 

On September 17, 2007, the Company entered into a drilling program with Hoactzin 

Partners, L.P. (“Hoactzin”) for ten wells consisting of approximately three wildcat wells and 

seven developmental wells to be drilled on the Company’s Kansas Properties (the “Ten Well 

Program”). Peter E. Salas, the Chairman of the Board of Directors of the Company, is the

controlling person of Hoactzin. He is also the sole shareholder and controlling person of Dolphin 

Management, Inc., the general partner of Dolphin Offshore Partners, L.P., which is the 

Company’s largest shareholder. 

Under the terms of the Ten Well Program, Hoactzin paid the Company $0.4 million for 

each well drilled in the Ten Well Program completed as a producing well and $0.25 million for 

each well that was non-productive. The terms of the Ten Well Program also provide that Hoactzin 

will receive all the working interest in the ten wells in the Program, but will pay an initial fee to 

the Company of 25% of its working interest revenues net of operating expenses. This is referred 

to as a management fee but, as defined, is in the nature of a net profits interest. The fee paid to 

the Company by Hoactzin will increase to 85% when and if net revenues received by Hoactzin 

reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout 

Point”) for its interest in the Ten Well Program. 

In March 2008, the Company drilled and completed the tenth and final well in the Ten 

Well Program. Of the ten wells drilled, nine were completed as oil producers and are currently 

producing approximately 36 barrels per day in total. Hoactzin paid a total of $3.85 million (the 

“Purchase Price”) for its interest in the Ten Well Program resulting in the Payout Point being 

determined as $5.2 million. The amount paid by Hoactzin for its interest in the Program wells 

exceeded the Company’s actual drilling costs of approximately $2.8 million for the ten wells by 

more than $1 million.

Under the terms of the Company’s agreement with Hoactzin, reaching the Payout Point 

may be accelerated by operation of a second agreement by which Hoactzin will apply 75% of the 

net profits it may receive from a methane extraction project discussed below developed by the 

Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”), to the 

Payout Point. 

On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the 

Ten Well Program, pursuant to the second agreement referred to above with the Company was 

conveyed a 75% net profits interest in the methane extraction project developed by MMC at the 

Carter Valley landfill owned and operated by Republic Services in Church Hill, Tennessee (the 

"Methane Project"). Net profits, if any, from the Project received by Hoactzin will be applied 

towards the determination of the Payout Point (as defined above) for the Ten Well Program. 

Through December 31, 2012, no payments have been made to Hoactzin for its 75% net 

profits interest in the Methane Project, because no net profits have been generated. 
F-21

The method of calculation of the net profits interest takes into account specific costs and 

expenses as well as gross revenues for the project. As a result of the startup costs and ongoing 

operating expenses, no net profits, as defined in the agreement, have been generated from project 

startup in April, 2009 through December 31, 2012 for payment to Hoactzin under the net profits 

interest conveyed. When the Payout Point is reached from either the revenues from the wells 

drilled in the Ten Well Program or Hoactzin’s share of the net profits from the Methane Project 

or a combination thereof, Hoactzin’s net profits interest in the Methane Project will decrease to a 

7.5% net profits interest. 

As of December 31, 2012, net revenues received by Hoactzin from the Ten Well Program 

totaled $4.6 million which leaves a balance of $0.6 million until the Payout Point is reached. On 

December 18, 2007, the Company entered into a Management Agreement with Hoactzin. On that 

same date, the Company also entered into an agreement with Charles Patrick McInturff 

employing him as a Vice-President of the Company. Pursuant to the Management Agreement 

with Hoactzin, Mr. McInturff’s duties while he is employed as Vice-President of the Company 

will include the management on behalf of Hoactzin 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 consideration for the Company entering into the Management Agreement, Hoactzin 

agreed that it would be responsible to reimburse the Company for the payment of one-half of Mr. 

McInturff’s salary, as well as certain other benefits he receives during his employment by the 

Company. In further 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 term of the 

Management Agreement ends on the earlier of the date Hoactzin sells its interest in its managed 

properties or five years. The Management Agreement terminated on December 18, 2012. As of 

the date of this Report, the Company is assisting Hoactzin with becoming operator of record of 

these wells and transferring the corresponding bonding liability from the Company to Hoactzin. 

The Company has entered into a transition agreement with Hoactzin whereby Hoactzin and its 

controlling member are indemnifying Tengasco for any costs or liabilities incurred by Tengasco 

resulting from such assistance, or the fact that Tengasco is still the operator of record on certain 

of these wells.

During the course of the Management Agreement, the Company became the operator of 

certain properties owned by Hoactzin. The Company obtained from IndemCo, over time, bonds 

in the face amount of approximately $10.7 million for the purpose of covering plugging and 

abandonment obligations for Hoactzin’s operated properties located in federal offshore waters in 

favor of the Bureau of Ocean Energy Management (“BOEM”), as well as certain private parties. 

On October 12, 2012, the BOEM terminated $1.1 million of these bonds leaving a balance of 

approximately $9.6 million at December 31, 2012.
F-22

In connection with the issuance of these bonds the Company entered into a Payment and 

Indemnity Agreement with IndemCo whereby the Company guarantees payment of any bonding 

liabilities incurred by IndemCo. Dolphin Direct Equity Partners, LP co-signed the Payment and 

Indemnity Agreement, thereby becoming jointly and severally liable with the Company for the 

obligations to IndemCo. Hoactzin has provided $6.6 million in cash to IndemCo as collateral for

these potential obligations. Dolphin Direct Equity Partners is a private equity fund controlled by 

Peter E. Salas that has a significant economic interest in Hoactzin. 

As operator, 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. 

During late 2009 and early 2010, Hoactzin undertook several significant operations, for which the 

Company contracted in the ordinary course. As a result of the operations performed in late 2009 

and early 2010, Hoactzin currently has significant past due balances to several vendors, a portion 

of which are included on the Company’s balance sheet. Payables related to these past due and 

ongoing operations remained outstanding at the end of 2012 and 2011 in the amount of $0.325

million and $0.265 million respectively. The Company has recorded the Hoactzin-related 

payables and the corresponding receivable from Hoactzin as of December 31, 2012 and 2011 in 

its Consolidated Balance Sheets under “Accounts payable – other” and “Accounts receivable –

related party”. During the quarters ended September 30, 2012 and December 31, 2012, Hoactzin 

had not made payments to reduce these past due balances. Based on these circumstances, the 

Company has elected to establish an allowance in the amount of $0.257 million for the balance 

outstanding at December 31, 2012 less $0.068 million paid by Hoactzin in early 2013. This 

allowance was recorded in the Company’s Consolidated Balance Sheets under “Accounts 

receivable – related party” and in its Consolidated Statements of Operations in “General and 

administrative”. No Tengasco funds have been advanced by Tengasco to pay any obligations of 

Hoactzin. No borrowing capability of Tengasco has been used by the Company in connection 

with its obligations under the Management Agreement, except for those funds used to 

collateralize the appeal bond with RLI Insurance Company (see Note 9 Commitments and 

Contingencies). 

4. Oil and Gas Properties

The following table sets forth information concerning the Company’s oil and gas 

properties: (in thousands):

December 31,

2012 2011

Oil and gas properties, at cost $ 43,351 $ 36,002

Unevaluated properties 457 268

Accumulated depreciation, depletion and amortization (19,108) (16,064)

Oil and gas properties, net $ 24,700 $ 20,206
F-23

During the years ended December 31, 2012, 2011, and 2010, the Company recorded 

depletion expense of $3.0 million, $2.2 million and $1.9 million, respectively.

5. Methane Project

The following table sets forth information concerning the Company’s methane project: 

(in thousands):

December 31,

2012 2011

Methane project, at cost $ 4,865 $ 5,421

Accumulated depreciation (420) (319)

Methane project, net $ 4,445 $ 5,102

During each of the years ended December 31, 2012, 2011, and 2010, the Company 

recorded depreciation expense of $0.1 million. In June 2012, the Company received a payment in

the amount of approximately $1.0 million from the United States Department of the Treasury for 

a cash payment in lieu of tax credits relating to the methane facilities. The payment to the 

Company was authorized under Section 1603 of Division B of the American Recovery and 

Reinvestment Act of 2009. This payment reduced the carrying amount of the Methane Project. 

6. Other Property and Equipment

Other property and equipment consisted of the following as of December 31, 2012: (in 

thousands)

Type Depreciable Life Gross Cost

Accumulated 

Depreciation

Net Book 

Value

Machinery and equipment 5-7 yrs $ 978 $ 878 $ 100

Vehicles 2-5 yrs 772 551 221

Other 5 yrs 63 63 -

Total $ 1,813 $ 1,492 $ 321

Other property and equipment consisted of the following as of December 31, 2011: (in 

thousands)

Type Depreciable Life Gross Cost

Accumulated 

Depreciation

Net Book 

Value

Machinery and equipment 5-7 yrs $ 969 $ 844 $ 125

Vehicles 2-5 yrs 789 488 301

Other 5 yrs 64 64 -

Total $ 1,822 $ 1,396 $ 426

The Company uses the straight-line method of depreciation for other property and 

equipment. The Company recorded depreciation expense of $0.2 million in each of the years 

2012, 2011, and 2010.
F-24

7. Assets Held For Sale and Discontinued Operations

Assets held for sale represent the carrying value of the pipeline asset of $1.4 million and 

$6.9 million as of December 31, 2102 and 2011, respectively. The determination of the pipeline 

value at December 31, 2012 was based on discussions and negotiations with a third party 

regarding the sale of the Pipeline asset.

The following table summarizes the amounts in net loss from discontinued operations, net of 

income tax presented in the consolidated statement of Operations for the years ended December 

31, 2012, 2011, and 2010: (in thousands)

For the Years Ended December 31,

2012 2011 2010

Revenues $ 30 $ 23 $ 5

Production costs and taxes (315) (260) (167)

Depreciation, depletion, and amortization (223) (176) (421)

Impairment (5,242) - (4,957)

Deferred income tax benefit 1,419 127 1,884

Current income tax benefit 20 - -

Net loss from discontinued operations, net of income tax $ (4,311) $ (286) $ (3,656)

8. Long-Term Debt

Long-term debt consisted of the following: (in thousands)

December 31, 2012 2011

Note payable to a financial institution, with interest only payment until maturity. $10,138 $ 11,531

Installment notes bearing interest at the rate of 5.5% to 8.25% per annum 

collateralized by vehicles with monthly payments including interest, insurance and 

maintenance of approximately $20,000 208 266

Total long-term debt 10,346 11,797

Less current maturities (100) (103)

Long-term debt, less current maturities $10,246 $ 11,694

Future debt payments to unrelated entities as of December 31, 2012 consisted of the following: 

(in thousands)

Year Bank Credit Facility Company Vehicles

2013 $ - $ 100

2014 $ - $ 83

2015 $ 10,138 $ 25

The bank credit facility payment is based on a maturity date of January 27, 2015.

At December 31, 2012, the Company had a revolving credit facility with F&M Bank & 

Trust Company (“F&M Bank”). Under the credit facility, loans and letters of credit are available 
F-25

to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $40 

million or the Company’s borrowing base in effect from time to time. As of December 31, 2012, 

the Company’s borrowing base was $21.5 million. The borrowing base was reduced to $20.5 

million with the March 6, 2013 amendment to the credit agreement. The credit facility is secured 

by substantially all of the Company’s producing and non-producing oil and gas properties and 

pipeline and the Company’s Methane Project assets. The credit facility includes certain 

covenants with which the Company is required to comply. These covenants include leverage, 

interest coverage, minimum liquidity, and general and administrative coverage ratios. The 

Company is in compliance with all covenants.

On March 14, 2012, the Company’s senior credit facility with F&M Bank after F&M 

Bank’s semiannual review of the Company’s then owned producing properties was amended to 

increase the Company’s borrowing base from $20 million to $23 million and extend the term of 

the facility to January 27, 2014. The interest rate remained the greater of prime plus 0.25% or 

5.25% per annum. The Company’s interest rate at December 31, 2012 was 5.25%.

On September 12, 2012, the Company’s senior credit facility with F&M Bank after F&M 

Bank’s semiannual review of the Company’s then owned producing properties was amended to 

decrease the Company’s borrowing base from $23 million to $21.5 million. The term of the 

facility and interest rate remained unchanged.

On January 31, 2013, the Company’s senior credit facility with F&M Bank was amended 

to revise the “Change in Control” definition. No other changes were made to the credit facility.

On March 6, 2013, the Company’s senior credit facility with F&M Bank after F&M 

Bank’s semiannual review of the Company’s then owned producing properties was amended to 

reduce the Company’s borrowing base from $21.5 million to $20.5 million and extend the term of 

the facility to January 27, 2015. The interest rate remained the greater of prime plus 0.25% or 

5.25% per annum. 

The total borrowing by the Company under the facility at December 31, 2012 and 

December 31, 2011 was $10.1 million and $11.5 million, respectively. The next borrowing base 

review will take place in June 2013. 

9. Commitments and Contingencies

The Company is a party to lawsuits in the ordinary course of its business. The Company 

does not believe that it is probable that the outcome of any individual action will have a material 

adverse effect, or that it is likely that adverse outcomes of individually insignificant actions will 

be significant enough, in number or magnitude, to have in the aggregate a material adverse effect 

on its financial statements. On March 1, 2010, the Company entered into a lease for office space 

in Knoxville, Tennessee. The term of the lease is 41 months (five of which are free) and expires 

on July 31, 2013. The payment on this lease was $7,284 per month through December 2011 and
F-26

is $7,294 per month for the remainder of the lease. Future non-cancellable commitments related 

to this lease total approximately $51,000 due in 2013.

Office rent expense for each of the three years ended December 31, 2012, 2011, and 2010

was $0.1 million.

The Company as designated operator was administratively issued an “Incidence of NonCompliance” by BOEM concerning one of the Hoactzin wells operated by the Company pursuant 

to the Management Agreement. This action calls for payment of a civil penalty of $386,000 for 

the late filing of certain reports in 2011 by a contractor on the facility. The Company has filed an 

appeal of this action in order to attempt to significantly reduce the civil penalty. This appeal 

required a fully collateralized appeal bond to stay payment of the obligation until the appeal is 

determined. On November 1, 2012, the Company posted and collateralized this bond with RLI 

Insurance Company. If the bond was not posted, the appeal would be administratively denied and 

the order to the Company as operator to pay the $386,000 penalty would be final. While the 

Company believes it will ultimately prevail in the appeal process, it is reasonably possible to 

expect that the Company may be required to pay a portion of this penalty. The Company 

estimates the range of this possible payment to be between zero and $386,000. 

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 markers 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. Following is a description of the 

valuation methodologies used for assets measured at fair value.
F-27

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.

The Company’s commodity derivative instruments are recorded at fair value on a 

recurring basis in our balance sheet with changes in fair value recorded in our income statement. 

The following table sets forth by level, within the fair value hierarchy, the Company’s assets and 

liabilities at fair value on a recurring basis as of December 31, 2012 and December 31, 2011. 

During 2012 and 2011, there were no changes in the fair value level classification. (in thousands)

December 31, 2012 Level 1 Level 2 Level 3

Derivative assets $- $- $-

Total assets at fair value $- $- $-

December 31, 2011 Level 1 Level 2 Level 3

Derivative assets $- $142 $-

Total assets at fair value $- $142 $-

The fair value of the Company’s commodity derivative instruments are estimated using a 

pricing model which has various inputs including forward price curves, volatilities, interest rates

and contract terms. Contract terms related to the Company’s commodity derivative instruments 

are defined in footnote 12 Derivatives.

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 following table sets forth by level, within the fair value hierarchy, the 

Company’s assets and liabilities at fair value on a recurring basis as of December 31, 2012. (in 

thousands)
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-28

Carrying Value 

Prior to 

Impairment

Level 1 Level 2 Level 3 Pre-Tax 

Non-Cash 

Impairment

Discontinued operations $ 6,642 $ - $ - $1,400 $ 5,242

Discontinued operations consisted of the Company’s Pipeline asset. Fair value at December 31, 

2012 was based on discussions and negotiations with a third party regarding the sale of the Pipeline asset

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, 2012 and December 31, 2011.

11. Derivatives

On July 28, 2009, the Company entered into a two-year agreement on crude oil pricing. This 

“costless collar” agreement was effective from August 1, 2009 through July 31, 2011 and had a $60.00 

per barrel floor and $81.50 per barrel cap on a volume of 9,500 barrels per month during the period from 

August 1, 2009 through December 31, 2010, and 7,375 barrels per month from January 1, 2011 through 

July 31, 2011. The prices referenced in this agreement were WTI NYMEX. While the agreement was 

based on WTI NYMEX prices, the Company receives a price based on Kansas Common plus bonus, 

which results in a price approximately $7 per barrel less than current WTI NYMEX prices. As of August 

1 2011, the “costless collar” agreement had expired.

On June 27, 2011 the Company entered into an agreement with Cargill, Incorporated for the 

period from August 1, 2011 through December 31, 2012 (“Cargill Agreement”). The agreement provides 

to the Company a $65 per barrel floor on a stated quantity of 10,000 barrels per month, which is 

approximately half of the Company’s current production of oil. If the average price falls below $65 per 

barrel, then Cargill will pay to the Company the difference between $65 and the lower average price for 

10,000 barrels per month in each month during when such lower average prices occur. However, unlike 

the “costless collar” arrangement, the Company will not have a price cap on any portion of its production 

volumes. The cost to the Company was $2.20 per barrel per month or a total of $374,000 for the entire 

period of the agreement. This cost was paid by the Company on June 27, 2011. These agreements were 

primarily intended to help maintain and stabilize cash flow from operations if lower oil prices return. 

As of December 31, 2011, the Company’s open forward positions were as follows (fair value is 

based on methodology described in footnote 10 Fair Value Measurement):
F-29

Period Monthly Volume Total Volume Floor/Cap NYMEX

Fair Value at

December 31, 2011 

Oil (Bbls) Oil (Bbls) $ per Bbl (in thousands)

1st Qtr 2012 10,000 30,000 $65.00-N/A $ 2

2nd Qtr 2012 10,000 30,000 $65.00-N/A $ 23

3rd Qtr 2012 10,000 30,000 $65.00-N/A $ 48

4th Qtr 2012 10,000 30,000 $65.00-N/A $ 69

Current Asset $ 142

No forward positions remained open as of December 31, 2012.

The Company records changes in the unrealized derivative asset or liability as a “Gain 

(loss) on derivatives” in the Consolidated Statements of Operations. The Company recorded 

unrealized gains of $0.14 million, $0.45 million, and $0.63 million during 2012, 2011, and 2010, 

respectively.

During 2011, the Company made settlement payments related to the “costless collar” of 

$0.86 million. During 2010, the Company made settlement payments of $0.13 million. These 

realized losses were recorded as a “Gain (loss) on derivatives” in the Consolidated Statements of 

Operation. During 2012, the Company made no settlement payments.

12. Asset Retirement Obligation

Our asset retirement obligations represent the estimated present value of the amount we 

will incur to plug, abandon and remediate our producing properties at the end of their productive 

lives in accordance with applicable laws. The following table summarizes the Company’s Asset 

Retirement Obligation transactions for the years ended December 31, 2011 and 2012: (in 

thousands):

Balance December 31, 2010 $ 1,437

Accretion expense 96

Liabilities incurred 57

Liabilities settled (165)

Revision in estimated liabilities 502

Balance December 31, 2011 $ 1,927
F-30

Accretion expense 132

Liabilities incurred 92

Liabilities settled (52)

Revisions in estimated liabilities -

Balance December 31, 2012 $ 2,099

The revisions in estimated liabilities in 2011 resulted primarily from increasing estimated 

plugging cost on Kansas and Tennessee wells based on the actual cost incurred on the wells

plugged in 2010 and 2011. 

13. 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 ended 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. The most recent 

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. 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. Furthermore, a 

participant in the Plan may not, immediately prior to the grant of an Incentive Stock Option, own 

stock in the Company representing more than ten percent of the total voting power of all classes 

of stock of the Company unless the per share option price specified by the Board for the Incentive

Stock Options granted such a participant is at least 110% of the fair market value of the 

Company’s stock on the date of grant and such option, by its terms, is not exercisable after the 

expiration of 5 years from the date such stock option is granted.

Stock option activity in 2012, 2011, and 2010 is summarized below:

2012 2011 2010

Shares

Weighted 

Average

Exercise

Price Shares

Weighted 

Average

Exercise

Price Shares

Weighted 

Average

Exercise

Price

Outstanding, 

beginning of year 1,471,000 $0.61 1,571,000 $0.60 3,021,000 $0.42

Granted 87,500 $0.85 186,745 $1.01 396,000 $0.44

Exercised (105,000) $0.50 (50,000) $0.57 (1,831,000) $0.27
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-31

Expired/cancelled (81,250) $1.12 (236,745) $0.82 (15,000) $0.58

Outstanding, end of 

year 1,372,250 $0.61 1,471,000 $0.61 1,571,000 $0.60

Exercisable, end of 

year 1,212,250 $0.62 1,231,000 $0.63 795,000 $0.70

The following table summarizes information about stock options outstanding and exercisable at 

December 31, 2012:

Weighted Average 

Exercise Price

Options Outstanding

(shares)

Weighted Average 

Remaining Contractual 

Life (years)

Options 

Exercisable

(shares)

$0.57 400,000 0.1 400,000

$1.44 50,000 0.4 50,000

$0.70 50,000 1.0 50,000

$0.50 400,000 2.8 240,000

$0.43 50,000 2.1 50,000

$0.44 241,000 2.7 241,000

$1.08 50,000 3.3 50,000

$1.16 18,750 3.3 18,750

$0.84 18,750 3.5 18,750

$0.72 18,750 3.8 18,750

$0.75 18,750 4.0 18,750

$1.07 18,750 4.2 18,750

$0.81 18,750 4.5 18,750

$0.73 18,750 4.7 18,750

1,372,250 1,212,250

During 2012, the Company issued the following options to each of the non-executive directors

that remain outstanding as of December 31, 2012. These options vested upon grant date.

Options Issued to 

Each Non-executive 

Director 

Total Options Issued to 

Non-executive Directors Exercise Price Grant Date Expiration Date

6,250 25,000 $ 0.75 1/3/2012 1/2/2017

6,250 25,000 $ 1.07 4/2/2012 4/1/2017

6,250 18,750 $ 0.81 7/2/2012 7/1/2017

6,250 18,750 $ 0.73 10/1/2012 9/30/2017

The weighted average fair value per share of options granted in 2012 was $0.47 and 2011 was 

$0.55 calculated using the Black Scholes option pricing model. 

Compensation expense related to stock options was $0.05 million in 2012 and was $0.2 million in 

2011 and $0.1 million in 2010. This expense is recorded in “General and administrative in the 
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-32

Consolidated Statements of Operations. At December 31, 2012, there was $0.06 million of total

unrecognized compensation costs related to unvested options that is expected to be recognized over a 

weighted average period of approximately 1.25 years. The fair value of stock options used to compute 

share based compensation is the estimated present value at grant date using the Black Scholes option 

pricing model with weighted average assumptions for 2012 of expected volatility of 65.0%, a risk free 

interest rate of 2.71% and an expected option life remaining from 0.1 to 4.8 years. The weighted average 

assumptions for 2011 were expected volatility of 59.3%, a risk free interest rate of 3.64% and an expected 

option life remaining from 1.1 to 4.8 years. The weighted average assumptions used for 2010 were 

expected volatility of 62.4%, a risk fee interest rate of 3.77% and an expected option life remaining for 

2.1 years to 4.7 years.

14. Income Taxes

The Company had taxable income for the years ended December 31, 2012 and 2010, but had no 

taxable income for the year ended December 31, 2011.

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, 2012 Continuing 

Operations

Discontinued 

Operations

Total

Statutory rate 34% 34% 34%

Tax (benefit) expense at statutory rate $ 2,229 $ (1,955) $ 274

State income tax (benefit) expense 43 - 43

Permanent difference 35 (84) (49)

Other 6 6

Net change in deferred tax asset valuation allowance - 600 600

Total income tax provision (benefit) $ 2,313 $ (1,439) $ 874

Year Ended December 31, 2011 Continuing 

Operations

Discontinued 

Operations

Total

Statutory rate 34% 34% 34%

Tax (benefit) expense at statutory rate $ 1,787 $ (141) $ 1,646

State income tax (benefit) expense 215 - 215

Permanent difference 28 14 42

Net change in deferred tax asset valuation allowance (1,741) - (1,741)

Total income tax provision (benefit) $ 289 $ (127) $ 162

Year Ended December 31, 2010 Continuing 

Operations

Discontinued 

Operations

Total

Statutory rate 34% 34% 34%

Tax (benefit) expense at statutory rate $ 920 $ (1,884) $ (964)

State income tax (benefit) expense (125) - (125)

Total income tax provision (benefit) $ 795 $ (1,884) $ (1,089)
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-33

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 does not believe that any 

of its positions it has taken will not 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. As of December 31, 2012, the Company had available 

approximately $21.8 million of federal net operating loss carryforwards to offset future taxable income. 

As of December 31, 2012, management using the “more likely that not” criteria for recognition 

determined that, upon sale of the Pipeline asset, the Company would not be able to utilize the state net 

operating loss carryforwards associated with TPC, and therefore has established an allowance for these 

state net operating loss carryforwards.

As of December 31, 2011, management using the “more likely than not” criteria for recognition 

determined that increases in current projections of taxable income were sufficient that the valuation 

allowance was no longer necessary, therefore, the $1.7 million valuation allowance was removed. 

During the year ended December 31, 2010, management, using the “more likely than not” criteria 

for recognition, elected to recognize a deferred tax asset of $1.1 million. The recognition of the deferred

tax asset in 2010 relates to net operating loss carryforwards, impairment of pipeline in 2010, and will 

provide a better matching of income tax expense with taxable income in future periods.

As of December 31, 2012, the Company had net operating loss carry forwards of approximately 

$21.8 million which will expire between 2019 and 2031 if not utilized. Our open tax years include all 

returns filed for 2008 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.

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

Year Ended December 31,

2012 2011

Net deferred tax assets (liabilities) - current:

Unrealized derivative loss - current $ - $ 164

Total deferred tax assets (liabilities) – current $ - $ 164

Net deferred tax assets (liabilities) – noncurrent:

Net operating loss carryforwards $ 8,550 $ 6,233

Oil and gas properties (154) 3,341

Property, Plant and Equipment 963 430

Asset retirement obligation 517 37
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-34

Tax credits 158 36

Valuation allowance (600)

Total deferred tax assets (liabilities) – noncurrent $ 9,434 $ 10,077

Net deferred tax asset (liability) $ 9,434 $ 10,241

15. 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 2012 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr 

Revenues $ 4,962 $ 5,222 $ 5,806 $ 4,567

Net income from continuing operations 954 1,152 1,279 859

Net (loss) from discontinued operations (81) (65) (60) (4,105)

Income per common share from continuing operations $ 0.02 $ 0.02 $ 0.02 $ 0.01

(Loss) per common share from discontinued operations $ (0.00) $ (0.00) $ (0.00) $ (0.07)

Fiscal Year Ended 2011 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr

Revenues $ 3,656 $ 4,782 $ 4,350 $ 4,274

Net income from continuing operations 436 1,037 1,237 2,256

Net (loss) from discontinued operations (82) (60) (51) (93)

Income per common share from continuing operations $ 0.01 $ 0.02 $ 0.02 $ 0.04

(Loss) per common share from discontinued operations $ (0.00) $ (0.00) $ (0.00) $ (0.00)

16. 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, 2012 and 2011 (in thousands):

Years Ended December 31,

2012 2011

Proved oil and gas properties $ 43,351 $ 36,002

Unproved properties 457 268

Total proved and unproved oil and gas properties $ 43,808 $ 36,270

Less accumulate depreciation, depletion and amortization (19,108) (16,064)

Net oil and gas properties $ 24,700 $ 20,206
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-35

Oil and Gas Related Costs

The following table sets forth information concerning costs incurred related to the Company’s oil 

and gas property acquisition, exploration and development activities (in thousands):

Years Ended December 31,

2012 2011 2010

Property acquisitions proved $ - $ - $ -

Property acquisitions unproved 188 - -

Exploration cost 4,608 708 80

Development cost 2,649 8,278 3,453

Total $ 7,445 $ 8,986 $ 3,533

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)

Year Ended December 31,

2012 2011 2010

Revenues $ 19,885 $ 16,862 $ 12,876

Production costs and taxes (5,610) (5,310) (5,308)

Depreciation, depletion and amortization (3,044) (2,195) (1,938)

Income from oil and gas producing activities $ 11,231 $ 9,357 $ 5,630

In the presentation above, no deduction has been made for indirect costs such as general corporate 

overhead or interest expense. No income taxes are reflected above due to the Company’s operating tax 

loss carry-forward position.

Estimated Quantities of Oil and Gas Reserves

The following table sets forth the Company’s net proved oil and gas reserves and the changes in 

net proved oil and gas reserves for the years ended December 31, 2010, 2011 and 2012. 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, 2009 2,273 116 2,293

Revisions of previous estimates 360 (64) 350

Improved recovery - - -

Purchase of reserves in place - - -
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-36

Extensions and discoveries 37 - 35

Production (174) (25) (178)

Sales of reserves in place - --- -

Proved reserves at December 31, 2010 2,496 27 2,500

Revisions of previous estimates 10 3 11

Improved recovery

Purchase of reserves in place

Extensions and discoveries 274 - 274

Production (189) (26) (193)

Sales of reserves in place

Proved reserves at December 31, 2011 2,591 4 2,592

Revisions of previous estimates (337) 61 (327)

Improved recovery - - -

Purchase of reserves in place - - -

Extensions and discoveries 186 - 186

Production (227) (43) (234)

Sales of reserves in place - - -

Proved reserves at December 31, 2012 2,213 22 2,217

Proved developed reserves at:

December 31, 2009 1,579 116 1,599

December 31, 2010 1,800 27 1,804

December 31, 2011 1,939 4 1,940

December 31, 2012 1,822 22 1,826

Proved undeveloped reserves at:

December 31, 2009 694 - 694

December 31, 2010 696 - 696

December 31, 2011 652 - 652

December 31, 2012 391 - 391
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-37

The following table identifies the 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 12/31/12 Year Ended 12/31/11 Year Ended 12/31/10

Oil Gas Total Oil Gas Total Oil Gas Total

Total proved reserves year-end 

reserve report $53,906 $5 $53,911 $69,748 $15 $69,763 $48,331 $13 $48,344

Proved developed producing 

reserves (PDP) $42,621 $5 $42,626 $46,606 $15 $46,621 $28,974 $13 $28,987

% of PDP reserves to total proved 

reserves 79% - 79% 67% - 67% 60% - 60%

Proved developed non-producing 

reserves $3,234 - $3,234 $3,977 - $3,977 $7,476 - $7,476

% of PDNP reserves to total proved 

reserves 6% - 6% 6% - 6% 15% - 15%

Proved undeveloped reserves (PUD)

$8,051 - $8,051 $19,165 - $19,165 $11,881 - $11,881

% of PUD reserves to total proved 

reserves 15% - 15% 27% - 27% 25% - 25%

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):

December 31,

2012 2011 2010

Future cash inflows $ 194,941 $ 229,366 $ 180,569

Future production costs and taxes (82,069) (82,086) (70,771)

Future development costs (7,894) (12,611) (13,283)

Future income tax expenses (19,472) (34,750) -

Future net cash flows 85,506 99,919 96,515

Discount at 10% for timing of cash flows (40,152) (48,010) (48,171)

Standardized measure of discounted future net cash flows $ 45,354 $ 51,909 $ 48,344
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-38

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):

December 31,

2012 2011 2010

Balance, beginning of year $ 51,909 $ 48,344 $ 28,187

Sales, net of production costs and taxes (14,275) (11,552) (7,568)

Discoveries and extensions, net of costs 6,967 10,923 2,099

Purchase of reserves in place - - -

Sale of reserves in place - - -

Net changes in prices and production costs (6,067) 15,428 15,554

Revisions of quantity estimates (9,883) 343 8,873

Previously estimated development cost incurred during the year 8,760 5,346 3,806

Changes in future development costs (1,919) (1,109) (3,168)

Changes in production rates (timing) and other (5,657) (2,336) (2,037)

Accretion of discount 6,223 4,376 2,598

Net change in income taxes 9,296 (17,854) -

Balance, end of year $ 45,354 $ 51,909 $ 48,344

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 prices used for December 31, 2012, 2011, and 2010, 

were $88.08, $88.53, $72.30 per barrel of oil and $2.76, $4.16, $4.89, per MCF of gas, respectively. The 

Company’s proved reserves as of December 31, 2012, 2011 and 2010 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 costs such as general corporate overhead or interest expense.

17. Subsequent Events

On January 2, 2013, options to purchase 18,750 common shares at $0.64 per share were issued to 

the Company’s non-executive directors. These options fully vested upon grant date and will expire on 

January 1, 2018.

On January 31, 2013, the Company’s senior credit facility with F&M Bank was amended to 

revise the “Change in Control” definition. No other changes we made to the credit facility.
Tengasco, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

F-39

On March 1, 2013, the Company entered into an agreement with Swan Creek Partners LLC to sell 

the Company’s Swan Creek and Pipeline assets for $1.5 million. Final closing of this transaction is 

contingent upon customary due diligence as well as certain regulatory and easement holder approvals. 

On March 6, 2013, the Company’s senior credit facility with F&M Bank and Trust Company, 

N.A. of Dallas, Texas (F&M Bank”) after F&M Bank’s semiannual review of the Company’s currently 

owned producing properties was amended to decrease the Company’s borrowing base from $21.5 million 

to $20.5 million and extend the term of the facility to January 27, 2015. The borrowing base remains 

subject to the existing periodic redetermination provisions in the credit facility. The interest rate remained 

the greater of prime plus 0.25% or 5.25% per annum. The maximum line of credit of the Company under 

the F&M Bank credit facility remained $40 million and the Company’s outstanding borrowing under the 

facility as of March 6, 2013 was $9.1 million.