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, 2006 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. 0-20975

 

TENGASCO, INC.

(Name of registrant as specified in its charter)

 

 

 

 

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 o No x

 

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 o No x

 

Indicate 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 o

 

Indicate by check mark if disclosure of delinquent filers in response to Item 405 of Regulation SK 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act. Large Accelerated Filer [ ] Accelerated Filer o Non-accelerated Filer x

 

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

 

State 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 (June 30, 2006 closing price $1.29): $48,086,530

 

State the number of shares outstanding of the registrant's $.001 par value common stock as of the close of business on the latest practicable date (March 1, 2007): 59,058,705

 

Documents Incorporated By Reference

 

The information required by Part III of the Form 10-K, to the extent not set forth herein, is incorporated herein by reference from the registrant's definitive proxy statement for the Annual Meeting of Shareholders to be held on April 30, 2007, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A not later than 120 days after the close of the registrant's fiscal year.

 

 

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                Table of Contents

 

 

 

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FORWARD LOOKING STATEMENTS

 

The information contained in this Report, in certain instances, includes forward-looking statements within the meaning of applicable securities laws. Forward-looking statements include statements regarding the Company’s “expectations,” “anticipations,” “intentions,” “beliefs,” or “strategies” regarding the future. Forward-looking statements also include statements regarding revenue, margins, expenses, and earnings analysis for 2006 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 statements. 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 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.

 

PART I

 

 

History of the Company

 

The Company was initially organized in Utah in 1916 for the purpose of mining, reducing and smelting mineral ores, under the name Gold Deposit Mining & Milling Company and 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.

 

Overview

 

The Company is in the business of exploring for, producing and transporting oil and natural gas in Kansas and Tennessee. The Company leases producing and non-producing properties with a view toward exploration and development and owns pipeline and other

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infrastructure facilities used to provide transportation services. The Company utilizes seismic technology to improve the discovery of reserves.

 

In 1998, the Company acquired from AFG Energy, Inc. (“AFG”), a private company, approximately 32,000 acres of leases in the vicinity of Hays, Kansas (the “Kansas Properties”). Included in that acquisition were 273 wells, including 208 working wells, of which 149 were producing oil wells and 59 were producing gas wells, a related 50-mile pipeline and gathering system, three compressors and 11 vehicles. The Company sold the Kansas gas producing wells, gathering system and compressors effective February 1, 2005. During 2006, the Kansas Properties produced an average of approximately 15,000 barrels of oil per month.

 

The Company’s oil and gas leases in Tennessee are located in Hancock, Claiborne, and Jackson counties. The Company has drilled primarily on a portion of its leases known as the Swan Creek Field in Hancock County focused within what is known as the Knox Formation, one of the geologic formations in that field. During 2006 the Company sold an average of approximately 378 thousand cubic feet of natural gas per day and 708 barrels of oil per month from 21 producing gas wells and 5 producing oil wells in the Swan Creek Field.

 

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 formed a wholly-owned subsidiary on December 27, 2006 named Manufactured Methane Corporation for the purpose of owning and operating treatment and delivery facilities using the latest developments in available technologies for the extraction of methane gas from non-conventional sources for delivery through the nation’s existing natural gas pipeline system, including the Company’s TPC pipeline system in Tennessee for eventual sale to natural gas customers.

 

General

 

 

The Company’s Kansas Properties presently include 130 producing oil wells in the vicinity of Hays, Kansas. The Company employs a full time geologist in Kansas to oversee acquisition of new properties, and exploration and exploitation of Kansas Drilling prospects on both newly acquired acreage and existing leases for development. The Company employs a full time production manager to oversee the daily function of all producing wells and to implement the work-over programs employed by the Company to boost production from older wells.

 

In 2006, the Company continued to focus its exploration and drilling activities in Kansas. During 2006, the Company also continued its lease acquisition program in Kansas to acquire oil and gas leases in areas near its previous lease holdings where the Company believes there is a likelihood of additional oil production. The Company continued to collect and analyze

 

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substantial seismic data to aid it in its drilling operations The Company intends in 2007 to continue to acquire additional leases in the area of its existing wells.               

 

In 2006, the Company drilled the last two wells of an eight-well drilling program in Kansas (the “Eight Well Program”). The Eight Well Program was offered to the holders of the Company’s Series A 8% Cumulative Convertible Preferred Stock (“Series A Shares”) in exchange for their Series A Shares. This resulted in the participants acquiring approximately an 81% working interest in the eight wells and the Company retaining the remaining 19% working interest. Under the terms of the Eight Well Program, the former Series A shareholders participating in the Eight Well Program will receive all of the cash flow from their 81% working interest in the eight wells until they have recovered 80% of the face value of the Series A Shares they exchanged for their interests in the Eight Well Program. At that point, for the rest of the productive lives of those eight wells, the Company will receive 85% of the cash flow from the 81% working interest in those wells as a management fee and the Series A shareholders will receive the remaining 15% of the cash flow. The Eight Well Program produced sufficient revenues to the participants in 2006 so that the Company estimates that the management fee will become due to the Company in 2007 resulting in approximately an additional $50,000 in revenues per month, depending upon commodity prices and continuing production levels from those wells.

 

In October, 2005 the Company accepted an exchange from Hoactzin Partners, L.P. (“Hoactzin”) of promissory notes made by the Company in the principal amount of $2,514,000 for a 94.3% working interest in a twelve well drilling program (the “Twelve Well Program”) by the Company on its Kansas Properties. The Company retained the remaining 5.7% working interest in the Twelve Well Program. The promissory notes exchanged were originally issued by the Company in connection with loans made to the Company by Dolphin Offshore Partners, L.P. (“Dolphin”) to fund the Company’s cash exchange to holders of its Series A, B and C Preferred Stock. 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, which is the Company’s largest shareholder.

 

In 2006, the Company drilled four wells in the Twelve Well Program bringing the total number of wells drilled in that Program to six. All but one of those wells is producing commercial quantities of oil.

 

On June 29th, 2006 the Company closed a $50,000,000 credit facility with Citibank Texas, N.A. The Company’s initial borrowing base was set at $2,600,000 and the Company borrowed that amount on June 29, 2006 and used $1.393 million of the loan proceeds to exercise its option to repurchase from Hoactzin Partners, L.P., the Company’s obligation to drill the final six wells in the Company’s Twelve Well Program. As a result of the repurchase, the Twelve Well Program was converted to a six well program, all of which had been drilled by the Company at the time of the repurchase. Consequently, as of July 1, 2006, all well-drilling obligations of the Company under both the Eight Well and Twelve Well Programs with former preferred stockholders as participants had been satisfied. If the Company had not exercised its

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repurchase option, Hoactzin would have received a 94% working interest in the final six wells of the Twelve Well Program. However, as a result of the repurchase, Hoactzin will now receive only a 6.25% overriding royalty in six Company wells to be drilled, plus an additional 6.25% overriding royalty in the six program wells that had previously been drilled as part of the Twelve Well Program.

 

Gross oil production to the Company’s interest in 2006 was enhanced by our interest in the drilling program wells, the work-over results on existing wells especially the polymer successes, and the 4 new wells drilled late in 2006 in which the Company was not required to share the working interest with any drilling program or other participants. Specifically, the wells in the Eight Well Program produced 4,897 barrels of oil; the wells in the Twelve Well Program now converted to a six well program produced 11,147 barrels; wells polymered produced 25,585 barrels; and, the four new wells produced 9,950 barrels in 2006. By December 2006 these investments in drilling program wells, work-overs/polymers, and four new wells accounted for almost 40% of our gross Kansas production. The Company had successive record quarterly production in all four quarters of 2006, and set an all time monthly record in November 2006 with 18,158 gross barrels of oil produced in a single month. The total 2006 Kansas oil production of 179,555 barrels compared to 128,765 barrels produced in 2005 was a 29% increase. This production increase also had the effect of adding 348,000 barrels of oil to the reserve basis for Kansas. All this was achieved while lowering costs per barrel on the production side.

 

There are also additional capital development projects that the Company is considering to increase current oil production with respect to the Kansas Properties, including recompletion of wells and major work-overs. Management has made the decision to simultaneously undertake as many of these projects that can be paid from the Company’s current cash flow as soon as the Company is able to obtain third party crews and equipment to perform the work. Workovers done to date on a limited scale have been successful in Kansas. The work-overs included a treatment of wells by injection of polymers (a type of plastic compound) that has sealed off almost all of the water from entering the combined oil/water fluid stream that is naturally produced from the wells, while at the same time increasing the total quantity of crude oil that is actually produced per day from the treated wells. Although there can be no assurances, similar work-overs when completed might reduce water production and its associated removal expense and increase oil production from many of the Company’s other existing oil wells in Kansas.

 

 

Amoco Production Company, during the late 1970’s and early 1980’s acquired approximately 50,500 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. In 1982, Amoco successfully drilled two natural gas discovery wells in the Swan Creek Field to the Knox Formation. These wells, once completed, had a high pressure and apparent volume of deliverability of natural gas. 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

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constructing a necessary 23-mile pipeline across three mountain ranges and crossing the environmentally protected Clinch River from Sneedville, Tennessee to deliver gas from the Swan Creek Field to the closest market in Rogersville, Tennessee. In July 1995, the Company concluded a legal action under state law and acquired the Swan Creek leases.

 

 

In July 1998, the Company completed Phase I of its pipeline from the Swan Creek Field, a 30-mile pipeline made of six and eight-inch steel pipe running from the Swan Creek Field into the main city gate of Rogersville, Tennessee. The cost of constructing Phase I of the pipeline was approximately $4,200,000. In March 2001, construction of Phase II of the Company’s pipeline system was completed. Phase II was an additional 35 miles of eight and 12-inch pipe laid at a cost of approximately $12.1 million, extending the Company’s pipeline from a point near the terminus of Phase I and connecting to a meter station at Eastman Chemical Company’s (“Eastman”) plant in Kingsport, Tennessee. The completed pipeline system extends 65 miles from the Company’s Swan Creek Field to Kingsport, Tennessee and was built for a total cost of $16,329,552.

 

 

In 2003 management had obtained state regulatory approval for drilling additional infield wells in the Swan Creek Field resulting in an increased density of wells. Management expected that an increased density of wells within the existing Swan Creek Field would result in additional reserves and reported those reserves as proven in accordance with reservoir engineering standards.

 

In 2004, the Company drilled and tested two new infield development wells in the Swan Creek Field. The results of these wells together with the accumulation of data from previously drilled wells and seismic data indicated that drilling new gas wells in the Swan Creek Field would not achieve any significant increase in daily gas production totals from the Field; the current wells in production in the Swan Creek Field would be capable of and would likely produce all the remaining reserves in that Field; and, that only limited additional gas reserves could be added with additional infield developmental drilling. Consequently, the Company has not drilled any new wells in the Swan Creek Field.

 

Because no drilling has occurred since 2004, and no drilling for natural gas directly in Swan Creek is anticipated in the future, the current production levels less decline are the sole value of natural gas reserves and production. The existing production and the current 21 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 from 2005 to 2006 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 the decline experienced over the 2005-2006 period, and that ongoing production from existing wells will tend to stabilize near current production levels.

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Variations in year-end natural gas prices and lack of interest to invest in Swan Creek in the foreseeable future, have resulted in an adjustment to the reserve volumes to reflect only the reserves associated with currently producing wells. The company maintains an interest and anticipates drilling additional oil prospects in Swan Creek. It also has an interest in seeking other exploration targets in Tennessee outside of Swan Creek but near our pipeline, with other industry partners.

 

The deliverability of natural gas from the Swan Creek Field will not be sufficient to satisfy the volumes deliverable under its contracts with Eastman and BAE in Kingsport, Tennessee. The Eastman contract provides that Eastman will buy a minimum of the lesser of eighty percent of that customer’s daily usage or 10,000 MMBtu per day, and the BAE contract provides that BAE will buy a minimum of all of that customer’s usage or 5,000 MMbtu per day after Eastman’s volumes have been provided. In 2006 the Company’s volume sold from the field was approximately 419 MMBtu per day. The Company’s contracts with these customers are only for natural gas produced from the Swan Creek Field. So long as that field is not capable of supplying these volumes of natural gas, the Company is not in breach or violation of these contracts. No penalty is associated with the inability of the Field to produce the volumes that the Company could deliver and buyers would be obligated to buy under its industrial contracts if the volumes were physically available from the Field. However, in the event that the Company were found to be in breach of its obligations for failure to deliver any volumes of gas that is produced from the Swan Creek Field to either of these customers, the agreements limit potential exposure to damages. Damages are limited to no more than $.40 per MMBtu for any replacement volumes that are proved in a court proceeding as having been obtained to replace volumes required to be furnished but not furnished by the Company.

 

During 2005, the Company had 21 producing gas wells and 5 producing oil wells in the Swan Creek Field. Sales from the Swan Creek Field during 2006 averaged 378 Mcf per day compared to 502 Mcf per day in 2005.

 

 

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”). The Agreement provides that the Company will purchase all the naturally produced gas stream presently being collected and flared at a municipal solid waste landfill serving the metropolitan area of Kingsport, Tennessee that is owned and operated by BFI in Church Hill, Tennessee. BFI’s facility is located about two miles from the Company’s existing pipeline serving Eastman Chemical Company (“Eastman”). Contingent upon obtaining suitable financing, the Company plans to acquire and install 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 gas stream by volume. The Company plans to construct a small diameter pipeline to deliver the extracted methane gas to the Company’s existing pipeline for delivery to Eastman.

 

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                              The Company is presently seeking to arrange suitable project financing for the production of gas from this non-conventional source. Total costs for the project are expected to be approximately $3.7 million, and commercial operations are expected to begin about eight months from closing of financing.  At current gas production rates and expected extraction efficiencies, when commercial operations of the Project begin, the Company would expect to deliver about 418 MMBtu per day of additional gas to Eastman, which would almost double the current volumes of natural gas being delivered to Eastman by the Company from its Swan Creek field. At the average natural gas price received by the Company in 2006, the anticipated net revenues to the Company would be approximately $1 million per year from this project. The gas supply from this project 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, currently estimated by BFI to occur between the years 2022 and 2026.

 

 

The Company is seeking to purchase and has attempted to acquire additional existing oil and gas production in the Mid-Continent (USA) area. The Company is particularly interested in areas of Kansas, Oklahoma, and Texas. Although financing plans are uncertain, management believes that when a suitable property becomes available, a combination of such a property with our current reserves would allow the Company to create a financing mechanism that would make a purchase of the property possible. However, there is no assurance that a suitable property will become available or that terms will be established leading to a completion of such a purchase.

 

The Company has evaluated other geological structures in the East Tennessee area that are similar to the Swan Creek Field. These target evaluations were made using available third party seismic data, the Company’s own seismic investigations, and drilling results and geophysical logs from the existing wells in the region. While these areas are of interest, and may be further evaluated at some future time, based on its review to date the Company does not currently intend to actively explore these areas with its own funds. However, the Company may consider entering into partnerships where further exploration and drilling costs can be largely borne by third parties. There can be no assurances that any third party would participate in a drilling program in these structures, that any of these prospects will be drilled, and if they were drilled that they would result in commercial production.

 

The Company also intends to establish and explore all business opportunities for connection of the pipeline system owned by the Company’s subsidiary TPC to other sources of natural gas or gas produced from non-conventional sources so that revenues from third parties for transportation of gas across the pipeline system may be generated. Although no assurances can be made, such connections may also enable the Company to purchase natural gas from other sources and to then market natural gas to new customers in the Kingsport, Tennessee area at retail rates under a franchise agreement already granted to the Company by the City of Kingsport, subject to approval by the Tennessee Regulatory Authority.

 

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                              The Company also intends to continue to explore other opportunities such as its methane extraction project in Church Hill, Tennessee to obtain natural gas or substitutes for natural gas from non-conventional sources if such gas can be economically treated and tendered in commercial volumes for transportation not only through the Company’s existing pipeline system but by other delivery mechanisms and through other interstate or intrastate pipelines or local distribution companies for the purposes of supplementing the Company’s revenues from the sale of the methane gas produced by these projects.

 

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, local utilities and private industry end-users. The principal markets for the Company’s natural gas are local utilities, private industry end-users, and natural gas marketing companies.

 

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, Eastman and BAE in Sullivan County, as well as other industrial customers in the Kingsport area. The Company has acquired all necessary regulatory approvals and necessary property rights for the pipeline system. The Company's pipeline can not only provide transportation service for gas produced from the Company's wells, but could provide transportation of gas for small independent producers in the local area as well. The Company could, although there can be no assurance, sell its products to certain local towns, industries and utility districts.

 

At present, crude oil produced by the Company in Kansas is sold to the Coffeyville Resources Refining and Marketing, LLC (“Coffeyville Refining”) in Kansas City, Kansas. Coffeyville Refining is solely responsible for transportation of the oil it purchases. 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. Crude oil produced by the Company in Tennessee is sold to the Ashland refinery in Kentucky and is transported to the refinery by contracted truck delivery at the Company’s expense.

 

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.     

 

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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 via 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 the 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 are larger with greater financial resources.

 

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

 

The Company anticipates no difficulty in procuring well drilling permits in any state. 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 prices for transporting the product.

 

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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

 

The Company is presently dependent upon a small number of customers for the sale of gas from the Swan Creek Field, principally Eastman, and other industrial customers in the Kingsport area with which the Company may enter into gas sales contracts.

 

At present, crude oil from the Kansas Properties is being purchased at the well and trucked by Coffeyville Refining which is 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.

 

Patents, Trademarks, Licenses, Franchises, Concessions,

Royalty Agreements or Labor Contracts, Including Duration

 

Royalty agreements relating to oil and gas production are standard in the industry. The amount of the Company's royalty payments varies from lease to lease.

 

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, 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 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.

 

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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 a seven-inch diameter 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 $2,000 bond is required for each well drilled. The Company currently has the requisite amount of bonds on deposit.

 

As part of the Company's purchase of the Kansas Properties it 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. 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. In addition, at the federal level, the Federal Energy Regulatory Commission regulates interstate transportation of natural gas under the Natural Gas Act. Other regulated matters include marketing, pricing, transportation and valuation of royalty payments.

 

The Company’s operations are also subject to numerous and frequently changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. 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

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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’s Board of Directors has adopted resolutions to form 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 what affect these present and future laws, rules and regulations will have on the Company's current and future operations.

 

Research and Development

 

The Company has not expended any material amount in research and development activities during the last two fiscal years. The Company, however, spent substantial amounts in 2006 for the acquisition of seismic data relating to the Company’s Kansas Properties and for three dimensional analysis of the acquired seismic data for the purpose of determining drilling targets with the maximum likelihood of being commercial producers of oil when drilled.

 

Number of Total Employees and Number of Full-Time Employees

 

The Company presently has twenty-five full time employees and one part-time employee.

 

Executive Officers of the Registrant

 

 

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                              The following table sets forth the names of all current executive officers of the Company. These persons will serve until their successors are elected or appointed and qualified, or their prior resignations or terminations.

 

 

 

 

Cary V. Sorensen is 58 years old. He is a 1976 graduate of the University of Texas School of Law and has undergraduate and graduate degrees form 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 litigation department of Enron Corp. before entering private practice in June, 1996. He has represented virtually all of the major oil companies headquartered in Houston and all of the pipeline and other operating subsidiaries of Enron Corp., 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

_________________________

 

²               The background and business experience of Jeffrey R. Bailey is incorporated by reference from the section entitled “Proposal No. 1: Election of Directors” in the Company’s Proxy Statement for the Company 2006 Annual Meeting of Stockholders.

 

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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.

 

Mark A. Ruth is 48 years old. He is a Certified Public Accountant with 24 years accounting experience. He received a B.S. degree in accounting with honors from the University of Tennessee at Knoxville. He has served as a project controls engineer for Bechtel Jacobs Company, LLC; business manager and finance officer for Lockheed Martin Energy Systems; settlement department head and senior accountant for the Federal Deposit Insurance Corporation; senior financial analyst/internal auditor for Phillips Consumer Electronics Corporation; and, as an auditor for Arthur Andersen and Company. On December 14, 1998 he became the Company’s Chief Financial Officer.

 

Robert M. Carter is 70 years old. He attended Tennessee Wesleyan College and Middle Tennessee State College between 1954 and 1957. For 35 years he was an owner of Carter Lumber & Building Supply Company and Carter Warehouse in Loudon County, Tennessee. He has been with the Company since 1995 and during that time has been involved in all phases of the Company's business including pipeline construction, leasing, financing, and the negotiation of acquisitions. Mr. Carter was elected Vice-President of the Company in March, 1996, as Executive Vice-President in April 1997 and on March 13, 1998 he was elected as President of the Company. He served as President of the Company until he resigned from that position on October 19, 1999. On August 8, 2000 he again was elected as President of the Company and served in that capacity until July 31, 2001. He has served as President of Tengasco Pipeline Corporation, a wholly owned subsidiary of the Company, from June 1, 1998 to the present.

 

 

The Company's Board of Directors has adopted a Code of Ethics that applies to the Company's financial officers and executive officers, including its Chief Executive Officer and Chief Financial Officer. The Company’s Board of Directors has also adopted a Code of Conduct and Ethics for Directors Officers and Employees. A copy of these codes can be found at the Company's internet website at www.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 Codes of Ethics can be obtained free of charge by writing to: Cary V. Sorensen, Secretary, Tengasco, Inc., 10215 Technology Drive, Suite 301, Knoxville, TN 37932.

 

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 450 Fifth Street, N.W.,

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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 Web site 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 such site is http://www.sec.gov.

 

The Company’s website is located at http://www.tengasco.com. Under the “Finance” section of the website, you may access, free of charge the Company’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Section 16 filings (Form 3, 4 and 5) and any amendments to those reports as reasonably practicable after the Company electronically files such reports with the SEC. The information contained on the Company’s website is not part of this Report or any other report filed with the SEC.

 

 

In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating the Company’s business and future prospects. The risk factors described below are not necessarily 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.

 

 

During the early stages of the development of its oil and gas business the Company has had a history of significant losses from operations, in particular its development of the Swan Creek Field, and has an accumulated deficit of $30,156,132 as of December 31, 2006. Although management has substantially reduced its cash operating expenses, these losses have had a material adverse impact on the operations of the Company’s business. The Company has been profitable in 2005 and 2006. However, in the event the Company experiences losses in the future it may curtail the Company’s development activities or force the Company to sell some of its assets in an untimely fashion or on less than favorable terms.

 

The Company’s Credit Facility with Citibank

 

Borrowings under the Company’s credit facility with Citibank Texas, N.A. 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

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though the amount borrowed remained the same, and its net 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, Citibank may choose to require repayment of the outstanding borrowings sooner than currently required by the agreement.

 

 

The Company’s future financial condition and results of operations will 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. Prices for oil and natural gas are subject to fluctuations in response to relatively minor 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 and the overall economic environment. A substantial or extended decline in oil or gas prices would have a material adverse effect on the Company’s financial position, results of operations, quantities of oil and gas that may be economically produced, and access to capital. Oil and natural gas prices have historically been and are likely to continue to be volatile. This volatility makes it difficult to estimate with precision the value of producing properties in acquisitions and to budget and project the return on exploration and development projects involving the Company’s oil and gas properties. In addition, unusually volatile prices often disrupt the market for oil and gas properties, as buyers and sellers have more difficulty agreeing on the purchase price of properties.

 

 

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 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.

 

Involve Substantial Costs and are Subject

to Various Economic Risks.

 

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                              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 significant expenditures to locate and acquire new producing properties and to drill exploratory and developmental wells. In conducting exploration and development activities, the presence of

unanticipated pressure or irregularities in formations, miscalculations or 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 and timing of drilling, completing and operating wells is often uncertain.

 

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 as oil prices rise and as a result 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 and natural gas prices generally stimulate increased demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. 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.

 

Reserves Will Result in the Decline of the Company’s

 

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 acquires additional properties containing proved reserves, conducts successful exploration and development drilling, or successfully applies new technologies or identifies additional behind-pipe zones or secondary recovery reserves, the Company’s proved reserves will decline materially as production from these properties continues. The Company’s future oil and natural gas production is therefore highly dependent upon the level of success in acquiring or finding additional reserves or other alternative sources of production.

 

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 net reserves to be commercially profitable after deducting drilling, operating, and other costs. In addition, 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

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them to know conclusively prior to drilling a well whether oil or natural gas is present or may be produced economically.

 

The ultimate cost 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 or 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 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. In addition, at the federal level, the Federal Energy Regulatory Commission regulates interstate transportation of natural gas under the Natural Gas Act. Other regulated matters include marketing, pricing, transportation and valuation of royalty payments.

 

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.

 

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                              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.

 

 

Exploration for and production of oil and natural gas and the Company’s transportation and other activities can be hazardous, involving unforeseen occurrences such as blowouts, cratering, fires and loss of well control, which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or 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 from Non-conventional Reserves Operations Involve Substantial Costs and are Subject

to Various Economic, Operational, and Regulatory Risks.

 

The Company’s operations in projects involving the extraction of methane gas from non-conventional 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. These risks could result in a 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.

 

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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.

 

 

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. To the extent that their services become unavailable, the Company would be required to retain other qualified personnel. The Company does not know whether it would be able to recruit and hire qualified persons upon acceptable terms. The Company does not maintain “Key Person” insurance for any of the Company’s key employees.

 

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 pending and/or 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 Sarbanes-Oxley Act of 2002, as well as rules subsequently implemented by the SEC and listing requirements subsequently adopted by the American Stock Exchange in response to Sarbanes-Oxley, have required changes in corporate governance practices, internal control policies and audit committee practices of public companies. Although the Company is a relatively small public company these rules, regulations, and requirements 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 new rules and

 

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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 Owns

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., which is the Company’s largest shareholder. At December 31, 2006, Mr. Salas, directly and through Dolphin owned 21,057,492 shares of the Company’s common stock and had options granting him the right to acquire an additional 50,000 shares of common stock. His ownership and voting control over approximately 36% 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.

 

 

 

 

Property Location, Facilities, Size and Nature of Ownership

 

 

The Company leases its principal executive offices, consisting of approximately 4,607 square feet located at 10215 Technology Drive, Suite 301, Knoxville, Tennessee at a rental of $5,279 per month and an office in Hays, Kansas at a rental of $500 per month.

 

Although the Company does not pay 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.

 

 

The Kansas Properties as of December 31, 2006 contained 138 leases totaling 27,837 acres in the vicinity of Hays, Kansas. The increase in the total volume of acreage of the Company’s Kansas Properties from 15,875 acres at the end of 2005 is primarily due to the Company’s plans to focus its drilling and exploration activities in Kansas and to expand its interests in this area. Accordingly, in the second quarter of 2006, the Company leased

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approximately 3,800 acres in Trego County, Kansas; in the third quarter the Company leased approximately 2,800 acres in Rooks County, Kansas; and, in October 2006, the Company acquired one of its largest contiguous lease blocks containing approximately 5,490 acres in Russell and Ellis Counties, Kansas. The terms on the Company’s original leases in the Kansas Properties were from 1 to 10 years. Most of these leases, however, are still in effect because they are being held by 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%. 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.

 

By April 2006, the Company had drilled the last two wells of its Eight Well Program thereby completing its drilling obligations under that Program. As stated in Item 1 of this Report, the Company has a 19% working interest in the eight wells in that Program and the Company’s former Series A shareholders retain the remaining 81% working interest in those eight wells. However, under the terms of the Eight Well Program, once the former Series A shareholders participating in that Program receive cash flow from their working interest equaling 80% of the face value of the Series A Shares they exchanged for their interests in the Program, thereafter, for the balance of the time those wells remain productive, the Company will receive 85% of the cash flow from the 81% working interest as a management fee and the Series A shareholders will receive the other 15% of the cash flow from their 81% working interest.

 

During the period from January to June 2006, the Company drilled four additional wells in its Twelve Well Drilling Program on its Kansas Properties bringing the total number of wells drilled in that Program to six. Under the terms of the Twelve Well Program, Hoactzin Partners, L.P. (“Hoactzin”) is to retain a 94.3% in the wells drilled in that Program with the Company retaining the remaining 5.7% working interest in that Program. See, “Item 1 - Business - The Kansas Properties.” On June 29, 2006, the Company used $1.393 million of the proceeds of a $2.6 million loan it received from Citibank Texas, N.A. to exercise its option under the Twelve Well Program to repurchase from Hoactzin the Company’s obligation to drill the final six wells of the Program. As a result of the exercise of its repurchase option, the Company’s drilling obligations under the Twelve Well Program have been satisfied and the Program has been converted to a six well program. Hoactzin will continue to receive proceeds from its 94.3% working interest in those six wells until such time that it receives an aggregate amount of $999,049, at which time Hoactzin will pay the Company a management fee equal to 85% of the net revenues attributable to its working interest in the Program for the remaining life of the six wells. In addition, Hoactzin will receive a six percent (6%) overriding royalty in the six wells in the Program and the next six wells drilled by the Company in Kansas.

 

During the last six months of 2006, the Company drilled an additional four wells in which it has a 100% working interest. Each of these wells are producing commercial quantities of oil.

 

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The Company's Swan Creek leases are on approximately 8,635 acres in Hancock, Claiborne and Jackson Counties in Tennessee. The decrease in the total volume of acreage of the Company’s Swan Creek leases from 19,251 acres at the end of 2005 is primarily due to the Company not renewing leases that were not in production. The initial terms of the Company’s Swan Creek leases vary from one to five years.

 

Working interest owners in oil and gas wells in which the Company has working interests are entitled to market their respective shares of production to purchasers other than purchasers with whom the Company has contracted. Absent such contractual arrangements being made by the working interest owners, the Company is authorized but is not required to provide a market for oil or gas attributable to working interest owners’ production. At this time, the Company has not agreed to market gas for any working interest owner to customers other than customers of the Company. If the Company were to agree to market gas for working interest owners to customers other than the Company’s customers, the Company would have to agree, at that time, to the terms of such marketing arrangements and it is possible that as a result of such arrangements, the Company’s revenues from such production may be correspondingly reduced. If the working interest owners make their own arrangements to market their natural gas to other end users along the Company’s pipeline, such gas would be transported by TPC at published tariff rates. The current published tariff rate is for firm transportation at a demand or “reservation” charge of five cents per MMBtu per day plus a commodity charge of $0.80 per MMBtu. If the working interest owners do not market their production, either independently or through the Company, then their interest will be treated as not yet produced and will be balanced either when marketing arrangements are made by such working interest owners or when the well ceases to produce in accordance with customary industry practice.

 

Reserve Analyses

 

LaRoche Petroleum Consultants, Ltd. (“LaRoche”) of Houston, Texas has performed reserve analyses of all the Company’s productive leases. LaRoche and its employees and its registered petroleum engineers have no interest in the Company, and performed these services at their standard rates. The net reserve values used hereafter were obtained from a reserve report dated February 9, 2007 (the “Report”) prepared by LaRoche as of December 31, 2006.

 

The Report indicates the Company’s “TOTAL PROVEN ALL CATEGORIES” reserves for the Company as of December 31, 2006 to be as follows: net production volumes of 1,712,006 barrels of oil and 1,307 MMCF of gas compared to 1,374,463 barrels of oil and 4,763 MMCF of gas reported by the Company as of the end of 2005 in its Annual report on Form 10-K for that year.

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The pre-tax present value discounted at 10% (PV10) as of December 31, 2006 is stated to be $26,469,192. The Report indicates the “proven developed producing” reserves for the Company as of December 31, 2006 to be as follows: net production volumes of 1,358,532 barrels of oil and 1,265 MMCF of gas compared to 1,091,135 barrels of oil and 2,814 MMCF of gas as reported by the Company at the end of 2005. The pre-tax present value discounted at 10% (PV10) as of December 31, 2006 is stated to be $20,962,018. The increase in oil reserves from 2005 to 2006 is reflective of the Company’s increased drilling activities in Kansas in 2006 and future drilling plans for 2007. The decrease in gas reserves from 2005 is due primarily to the Company’s determination not to drill any new wells in its Swan Creek Field and the substantial drop in the price used to calculate the gas reserves from $11.54 per Mcf in 2005 to $8.33 per Mcf in 2006.

 

In substance, the 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. The net reserve values in the Report were adjusted to take into account the working interests that have been sold by the Company in various wells.

 

The Company believes that the reserve analysis reports prepared by LaRoche for the Company’s Kansas and Tennessee Properties provide an essential basis for review and consideration of the Company’s producing properties by all potential industry partners and all financial institutions across the country. It is standard in the industry for reserve analyses such as these to be used as a basis for financing of drilling costs.

 

The Company has not filed the Report prepared by LaRoche or any other reserve reports with any Federal authority or agency other than the SEC. The Company, however, has filed the information in the Report of the Company’s reserves with the Energy Information Service of the Department of Energy in compliance with that agency’s statutory function of surveying oil and gas reserves nationwide.

 

The term "Proved Oil and Gas Reserves" is defined in Rule 4-10(a)(2) of Regulation S-X promulgated by the SEC as follows:

 

2. Proved oil and gas reserves. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e.,

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prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.

 

i.      Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

 

ii.            Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

 

iii.          Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as indicated additional reserves; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

 

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 interests or other parties’ working interest.

 

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_________________________

³               A “BOE is a barrel of oil equivalent. A barrel of oil contains approximately 6 Mcf of natural gas by heating content. The volumes of gas produced have been converted into “barrels of oil equivalent” for the purposes of calculating costs of production.

⁴               Figures in this column reflect the fact that the Company sold all of the gas producing wells on its Kansas Properties on March 4, 2005 effective as of February 1, 2005. Thus, gas production is only through January 2005.

⁵               Although the total cost of production for the Kansas Properties in 2005 as compared to 2004 remained relatively constant, the cost per BOE decreased because of the costs related to a back-log of work-overs on wells performed in 2005.

⁶               Although the total cost of production for the Swan Creek Field in 2006 as compared to 2005 remained relatively constant, the cost per BOE decreased because of cost control measures implemented by the Company.

⁷               Although the actual total cost of production for the Swan Creek Field in 2005 as compared to 2004 remained relatively constant, the cost per BOE increased because of the decrease in production volumes of oil and gas.

⁸               Although the actual total cost of production for the Swan Creek Field in 2004 as compared to prior years remained constant, the cost per BOE increased substantially because of a decrease in production volumes of oil and gas.

 

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Oil and Gas Drilling Activities

 

 

In 2006, the Company drilled ten new wells in Kansas. These wells included the last two wells of the Company’s Eight Well Program and four wells in the Company’s Twelve Well Program which, as stated above, has now been converted to a completed six well program. The Company has a 100% working interest in the other four wells drilled in Kansas in 2006. All wells drilled in 2006 have produced in the aggregate a cumulative total of 25,994 barrels of oil.

 

The results of the wells drilled in Kansas as of December 31, 2006 are set out in the following table. Unless otherwise indicated the Company has a 100% working interest in the wells.

 

 

 

The Company continues to pursue incremental production increase where possible in the older wells, by using recompletion techniques to enhance production from currently producing intervals.

 

 

In 2006, the Company did not drill any new wells in the Swan Creek Field. The Company believes that drilling new gas wells in the Field will not contribute to achieving any significant increase in daily gas production totals from the Field. As a result, the Company does not have any plans at the present time to drill any new gas wells in the Swan Creek Field.

 

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The following tables set forth for the fiscal years ending December 31, 2004, 2005, and 2006 the number of gross and net development wells drilled by the Company. The wells drilled in 2006 refer to the final two wells drilled in the Eight Well Program, the final four wells in the Twelve Well Program as well as four other wells drilled in Kansas in which the Company has a 100% working interest. The term gross wells means the total number of wells in which the Company owns an interest, while the term net wells means the sum of the fractional working interests the Company owns in gross wells.

 

 

 

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, 2006. 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.

 

 

Developed and Undeveloped Oil and Gas Acreage

 

As of December 31, 2006, the Company owned working interests in the following developed and undeveloped oil and gas acreage. Net acres refers to the Company’s interest less the interest of royalty and other working interest owners.

 

 

 

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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.

 

 

 

PART II

 

 

 

The Company's common stock is listed on the American Stock Exchange (“AMEX”) under the symbol TGC. The range of high and low closing prices for shares of common stock of the Company during the fiscal years ended December 31, 2006 and December 31, 2005 are set forth below.

 

 

 

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Holders

As of March 1, 2006 the number of shareholders of record of the Company's common stock was 346 and management believes that there are approximately 7,316 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 2006 and has no present plans to declare any further dividends with respect to its common stock.

 

Recent Sales of Unregistered Securities

 

During the fourth quarter of fiscal 2006, the Company issued 22,267 shares of its common stock pursuant to the exercise of warrants issued by the Company to members of the plaintiff class as part of the settlement of the action entitled Paul Miller v. M. E. Ratliff and Tengasco, Inc., United States District Court for the Eastern District of Tennessee, Knoxville, Docket Number 3:02-CV-644. Those warrants are exercisable for a period of three years from date of issue at $0.45 per share and are exempt from registration pursuant to section 3(a) (10) of the Securities Act of 1933, as amended. Any unregistered equity securities that were sold or issued by the Company during the first three quarters of Fiscal 2006 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 or any of its affiliates repurchased any of the Company’s equity securities during 2006.

 

Equity Compensation Plan Information

 

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

 

Performance Graph

 

The graph below compares the cumulative total stockholder return on the Company’s common stock with the cumulative total stockholder return of (1) the American Stock Exchange Index and (2) the Standard Industrial Code Index for the Crude Petroleum and Natural Gas Industry, assuming an investment in each of $100 on December 31, 2001. The performance graph represents past performance and should not be considered to be an indication of future performance.

 

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COMPARISON OF CUMULATIVE TOTAL RETURN OF ONE OR MORE

COMPANIES, PEER GROUPS, INDUSTRY INDEXES AND/OR BROAD MARKETS

 

 

 

 

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The following selected financial data has been derived from the Company’s financial statements, and should be read in conjunction with those financial statements, including the related footnotes.

 

Year Ended December 31,

 

 

 

 

Year Ended December 31,⁹¹⁰

 

 

 

_________________________

 

¹⁰             On July 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 150 under which mandatorily redeemable preferred stock shall be reclassified at estimated fair value to a liability. Thus, in 2003, it was determined that each of the Company’s series of preferred stock qualifies as shares subject to mandatory redemption and should be classified as a liability.

 

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Results of Operations

 

The Company incurred a net income to holders of common stock of $2,141,364 or $0.04 per share in 2006 compared to a net income of $1,088,028 or $0.02 per share in 2005 and compared to a net loss of $(1,994,025) or ($0.05 per share) in 2004.

 

The Company realized revenues of $9,001,681 in 2006 compared to $7,172,876 in 2005 and compared to $6,109,474 in 2004. Revenues increased $1,828,805 from 2005 due primarily to an increase in oil production in Kansas of approximately 28,871 net barrels of oil (“bbls”) over 2005 levels. An increase in oil prices accounted for 36% of the increased revenues in 2006 and the increase in produced volumes accounted for 64% of the increased revenues. The Company has offset the normal decline curve in its Kansas properties with additional drilling and well work-overs. The gross volumes of oil of 183,013 bbls would have been approximately 147,000 bbls without additional drilling and well work-overs. The Company sold 134,164 bbls of oil in 2005 and 118,088 in 2004. The volume of gas sold from the Swan Creek Field decreased to 138,078 Mcf in 2006 from 183,399 Mcf in 2005 and the volume of oil sold from Swan Creek Field decreased to 8,493 barrels in 2006 from 10,388 barrels in 2005. The decline in volumes of oil and gas produced in the Swan Creek Field from existing wells is normal for producing wells and the declines as experienced were not unexpected. The Company’s gas production in Kansas in 2005 was only for the month of January 2005 (20,729 Mcf) as the Company’s Kansas gas field was sold on March 4, 2005 with the buyer’s production being retroactive to February 1, 2005. The Kansas gas field had produced 261,446 Mcf of gas in 2004.

 

Gas prices received for sales of gas from the Swan Creek Field averaged $7.27 per Mcf in 2006, $8.74 per Mcf in 2005, and $6.13 in 2004. Oil prices received for sales of oil from the Swan Creek field averaged $60.39 per barrel in 2006, $53.90 per barrel in 2005, and $36.57 in 2004. Oil prices received for sales of oil in Kansas averaged $60.84 per barrel in 2006, $53.48 per barrel in 2005, and $39.41 in 2004.

 

The Company’s subsidiary, TPC, had pipeline transportation revenues of $87,822 in 2006, $94,911 in 2005, and $92,599 in 2004. The decreases in revenues in 2006 and 2005 from 2004 resulted from the decrease in volumes of gas produced from the Swan Creek Field.

 

Production costs and taxes in 2006 of $3,287,233 remained consistent with levels in 2005 of $3,046,460 and in 2004 of $3,364,429.

 

Depletion, depreciation, and amortization increased to $1,911,416 in 2006 from $1,605,043 in 2005 which was a decrease from $2,067,566 in 2004. The increase in 2006 is due to a change in focus by the Company toward drilling in Kansas rather than in Tennessee, therefore removing drilling and development locations in Tennessee. The decrease in 2005 from 2004 levels was due mainly to depletion levels on the Kansas properties in 2004 decreasing in 2005 due to the sale of the Kansas gas field effective February 1, 2005.

 

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                              The Company’s general and administrative costs of $1,293,109 in 2006 remained generally consistent with 2005 levels of $1,322,616 and 2004 levels of $1,177,183. The 2006 and 2005 costs included non-cash charges related to stock options of $159,160 and $103,400 respectively.

 

Interest expense for 2006 decreased significantly over 2005 and 2004 levels. The substantial decrease is the result of the payoff in 2004 of the Company’s loans from Bank One, N.A. and Dolphin Offshore Partners, L.P. and the conversion in 2004 and 2005 of all the Company’s preferred stock, which was subject to mandatory redemption, into either interests in a drilling program, common stock or cash payoffs. As of December 31, 2006 the Company’s only debt financing are vehicle loans totaling $195,801 and the CitiBank loan of $2,600,000.

 

The Company’s public relations costs remained stable at $26,037 for 2006, compared to $30,020 for 2005 and $35,347 for 2004 as the Company continued to apply cost saving methods in the preparation of its annual report and in publishing of press releases.

 

Professional fees in 2006 were $173,932 compared to $263,800 in 2005 and $779,180 in 2004. These fees were greatly reduced in 2005 due to the elimination of outside counsels’ legal fees following a settlement of Company litigation in 2004. The remaining professional fees in 2006 relate primarily to audit and engineering services.

 

During 2004, the Company recorded a gain from extinguishment of debt in the amount of $336,820 from the Bank One litigation settlement and a gain on disposal of preferred stock of $458,310. The Company also recorded a loss on sale of a drilling rig during 2004 of $107,744. The Company recorded a gain on disposal of Preferred Stock of $655,746 in 2005.

 

Liquidity and Capital Resources

 

Management believes that the Company’s foundation for future growth began to solidify in 2004. In 2004, all material litigation involving the Company was resolved, eliminating the substantial ongoing costs and expenses of such litigation. Capital restructuring began in February 2004, when the Company’s rights offering to its then-shareholders successfully raised sufficient capital to pay in full all pre-existing secured debt in the amount of $3.8 million, most of which had been obtained at relatively high interest rates. Also in early 2004 certain unsecured convertible notes entered into in 1998 in the principal amount of $1.5 million were fully paid, and still other convertible notes entered into in 2002 in the original principal amount of $650,000 were paid in full in March 2004.

 

In December, 2004 the Company completed an exchange offer to the thirteen holders of all of the Company’s Series A 8% Cumulative Convertible Preferred Stock (“Series A Shares”) in the face value of $2,867,900. Seven of the thirteen holders elected the cash exchange option, and the face value of $1,085,000 of Series A Shares was exchanged for a cash payment of $723,369.

 

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The Company obtained funds for the exchange from cash on hand and the proceeds of a loan from Dolphin Offshore Partners, L.P. (“Dolphin”) the Company’s largest shareholder. 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. The loan from Dolphin was in the form of a secured note in principal amount of $550,000 bearing 12% interest per annum. Five of the thirteen Series A shareholders selected a drilling program exchange option and on December 31, 2004 the face value of $1,582,900 of Series A Shares plus dividend value of $31,658 was exchanged for 6.5 of the eight units in an eight well drilling program on the Company’s Kansas Properties (the “Eight Well Program”). In December 2005 the last remaining Series A preferred shareholder exchanged his preferred stock for cash on essentially identical terms as received by the other Series A owners who had exchanged their shares for cash.

 

In early 2005, the Company elected to sell its gas producing properties in Rush County, Kansas for $2.4 million and to utilize all the net proceeds of the sale to pay down the $2.5 million debt to Dolphin incurred by the Company to fund the settlement of the litigation with the Company’s former primary lender, Bank One N.A., in May, 2004. This had the effect of reducing the principal balance of the note evidencing that loan from $2.5 million to $150,000, correspondingly reducing the high interest payments on that note and reducing the total secured debt owed by the Company to Dolphin to approximately $700,000 represented by a promissory note dated May 19, 2005, in the principal amount of $700,000 to Dolphin (the “$700,000 Note”).

 

In August 2005, all of the holders of the Company’s Series B 8% and C 6% Cumulative Convertible Preferred Stock (the “Series B and Series C Shares”) in the total aggregate value of $5,113,045.39 consisting of face value, dividends, and interest exchanged their Series B and C shares for cash or for the Company’s common stock. The cash option exchange provided for a cash payment equal to 66.67% of the face value together with any unpaid accrued dividends. Holders of approximately 53.2% of the face value of outstanding Series B and C Shares selected this option, exchanging preferred shares having an aggregate value of $2,721,140.39 for cash payments totaling $1,814,184.30. The Company obtained the funds for this exchange primarily from proceeds of a loan of $1,814,000 from Dolphin evidenced by a secured promissory note bearing 12% interest (the “$1,814,000 Note”).

 

The second option offered to the holders of the Series B and C Shares was to exchange their Series B and C Shares for four shares of the Company’s common stock for each dollar of the face value and unpaid accrued dividends and interest on their Series B and C Shares. The holders of the remaining aggregate value of $2,391,905 or 46.8% of the Series B and C shares including Dolphin selected this option. As a result, a total of 9,567,620 shares of the Company’s common stock were issued to holders of Series B and C Shares. Of this total number, 4,595,040 shares of unregistered common stock were issued to Dolphin in exchange for the $1,148,760 in aggregate value of the Series B shares held by Dolphin. As a result of this exchange, as of August 22, 2005 the Company no longer had any preferred stockholders and no further obligations under the Series B and C shares.

 

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                              On October 5, 2005 the Company and Hoactzin Partners, L.P. (“Hoactzin”) signed an agreement whereby Hoactzin surrendered the $700,000 and $1,814,000 Notes and exchanged the Company’s obligation to repay this principal amount of $2.514 million for a 94.275% working interest in a new twelve well drilling program (the “Twelve Well Program”) on the Company’s properties in Kansas. The Company retained the 5.725% working interest in the Twelve Well Program not owned by Hoactzin. The principal of the Notes exchanged by Hoactzin represented the funds paid by the Company for the previous exchanges for cash of the Company’s Series A, B, and C preferred stock. The controlling person of Hoactzin is Peter E. Salas, the Chairman of the Company’s Board of Directors and the controlling person of Dolphin. Under the terms of the Twelve Well Program, the Company retained an option expiring March 31, 2006 to repurchase from Hoactzin the obligations to drill the final six wells of the Twelve Well Program for one half of the principal of notes exchanged by Hoactzin, plus interest on that amount at 6% per annum until the date of any repurchase, plus a 1/16 overriding royalty to Hoactzin on all wells drilled in the Twelve Well Program. Payout and management fee calculations would also be adjusted to reflect any reduction to a six well program.

 

On June 29, 2006 the Company closed a $50,000,000 revolving senior credit facility between the Company and Citibank Texas, N.A. in its own capacity and also as agent for other banks.  Under the facility, loans and letters of credit will be available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $50,000,000 or the borrowing base in effect from time to time. The Company’s initial borrowing base was set at $2,600,000.  The initial loan under the facility with Citibank closed on June 29, 2006 in the principal amount of $2.6 million, bearing interest at a floating rate equal to LIBOR plus 2.5%, resulting in a current rate of interest of approximately 8.2%.  Interest only is payable during the term of the loan and the principal balance of the loan is due thirty-six months from closing.   The facility is secured by a lien on substantially all of the Company’s producing and non-producing oil and gas properties and pipeline assets.

 

On June 29, 2006 the Company used $1.393 million of the proceeds of the $2.6 million loan to exercise the Company’s option to repurchase from Hoactzin Partners, L.P., the Company’s obligation to drill for Hoactzin the final six wells of the Company’s Twelve Well Program.  If the Company had not exercised its repurchase option, Hoactzin would have received a 94% working interest in the final six wells of the Twelve Well Program until payout as established under the terms of the Twelve Well Program program.  However, as a result of the terms of the repurchase option, Hoactzin will receive only a 6.25% overriding royalty in the next six Company wells to be drilled, plus an additional 6.25% overriding royalty in the six Program Wells that have previously been drilled.  As a further result of the repurchase, the Twelve Well Program was converted into a six well program, and because six wells had been drilled by the Company as of June 30, 2006 the drilling obligation in this program were satisfied upon exercise of the repurchase option.  Consequently, as of June 30, 2006, all well-drilling obligations of the Company owed to participants have been satisfied as to both the Eight Well Program (offered to the former Series A preferred stockholders) and the Twelve Well Program (offered to Hoactzin and converted to a 6-well program upon the Company’s repurchase of the obligation to drill the last six wells as described above). 

 

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As of December 31, 2006 all of the obligations of the Company to drill wells under the Eight Well Program and Twelve (now Six) Well program have been satisfied. Under the terms of those programs, upon payment to the participants of 80% of the value invested in the program from proceeds from production, the participants will pay the Company a management fee of 85% of their proceeds. As to the Eight Well Program, that point is expected to be reached in early 2007 resulting in an increase in revenues from these wells to the Company of approximately $50,000 per month at current volumes and prices. As to the Twelve (now 6) Well Program, that point is expected to be reached some time in 2008 or 2009 depending upon prices and production levels experienced from the wells in that Program.

 

As of June 30, 2006 the Company had completed a total reworking of its balance sheets that has been occurring since February 2004.   The Company has resolved all major litigation and eliminated the accompanying legal fees. The Company’s successful rights offering in February 2004 raised capital to pay off substantial debt.  The Company also sold its small block of gas properties in Kansas obtaining a dollar benefit of high gas prices reflected in the $2.4 million sales price while simultaneously eliminating the high operating expenses of those properties. The Company used proceeds of the gas property sale to further pay down debt.  The Company has also met its obligations to all of its preferred stockholders by exchanging their preferred stock either for cash, stock, or drilling program interests, and has accordingly cancelled all of the Series A, B, and C preferred stock. The Company has completed all of its well-drilling obligations to the drilling program participants out of its own cash flow from operations and without additional borrowing for drilling.  The Company continues to successfully rework existing wells, to drill new oil wells in Kansas and is acquiring additional lease acreage to increase production and to grow its reserves through the drill bit.   All the while the Company has benefited from the currently high commodity prices for oil and gas and has used higher prices and increasing production volumes to conservatively fuel the reworking of the balance sheets and to prepare the Company for those times in the future when commodity prices may not be as favorable--which is a part of the business cycle that is well known and almost universally expected to some degree as an element of the oil and gas industry. 

 

Net cash provided by operating activities for 2006 was $4,353,966 compared to net cash provided by operating activities of $2,113,763 in 2005. The Company’s net income in 2006 increased to $2,141,364 from $1,088,028 in 2005. The impact on cash provided by operating activities was due to the net income for 2006 and was increased by non-cash depletion, depreciation, and amortization of $1,863,930 and by non-cash compensation and services paid by insurance of equity instruments of $159,160. Cash flow provided in working capital items in 2006 was $122,152 compared to cash used in working capital items of $209,601 in 2005. This resulted in 2006 from decreases from 2005 in accounts receivable of $434,565 offset by a decrease in other accrued liabilities of $251,327.

 

Net cash provided by operating activities for 2005 was $2,113,763 compared to net cash used in operating activities of ($370,137) in 2004. The Company recorded net income in 2005 of $1,088,028 from a net loss of ($1,994,025) in 2004. The increase in the amount of cash provided in operating activities in 2005 was due to the Company’s net income for 2005 and was increased by non-cash depletion, depreciation, and amortization of $1,605,043, non-cash

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compensation and services paid by insurance of equity instruments of $103,400 and accretion of liabilities of $242,008. Cash flow used in working capital items in 2005 was $209,601 compared to cash used in working capital items of $913,831 in 2004. This resulted in 2005 from an increase in accounts receivable of $447,653, and an increase in inventory of $154,586 offset by an increase in accounts payable of $277,458.

 

Net cash used in investing activities amounted to $4,413,185 for 2006 compared to net cash provided by investment activities in the amount of $2,166,854 for 2005. The increase in net cash used in investing activities during 2006 was primarily attributable to an increase in oil and gas properties of $5,239,862 offset by a decreased drilling program portion of additional drilling costs of $1,067,400.

 

Net cash provided by investing activities amounted to $2,166,854 for 2005 compared to net cash used in the amount of $876,854 for 2004. The net cash provided by investing activities during 2005 was primarily attributable to the sale of the Kansas properties of $2,651,770 offset by increase in Kansas oil and gas properties net of the Kansas drilling programs portion of $402,876.

 

Net cash provided by financing activities increased to $167,915 in 2006 from cash used in financing activities of $4,287,383 in 2005. In 2006 the primary sources of financing included proceeds from borrowings of $2,732,145 compared to $155,075 in 2005. The primary use of cash in financing activities in 2006 was to repay the drilling program liability of $2,324,400.

 

Net cash used in financing activities amounted to $4,287,383 in 2005 from net cash provided by financing activities of $1,202,060 in 2004. In 2005 the primary use of funds was repayment of borrowers of $3,182,636, repayment of redeemable liabilities of $4,241,874, repayment of drilling programs of $1,945,203 offset by proceeds from issuance of common stock of $2,391,905 and a new drilling program of $2,514,000 and proceeds from borrowing of $155,073.

 

Critical Accounting Policies

 

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

 

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The Company recognizes revenues based on actual volumes of oil and gas sold and delivered to its customers. Natural gas meters are placed at the customers’ location and usage is billed each month. Crude oil is stored and at the time of delivery to the customers, revenues are recognized.

 

 

The Company follows the full cost method of accounting for oil and gas property acquisition, exploration and development activities. Under this method, all productive and non-productive costs incurred in connection with the acquisition of, exploration for and development of oil and gas reserves for each cost center are capitalized. Capitalized costs include lease acquisitions, geological and geophysical work, day rate rentals and the costs of drilling, completing and equipping oil and gas wells. Costs, however, associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs. The capitalized oil and gas property, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties excluded from the costs being amortized. No ceiling write-downs were recorded in 2006, 2005 or 2004.

 

 

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 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, 2006 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.

 

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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.         

 

 

The Company is required to record the effects of contractual or other legal obligations on well abandonments for capping and plugging wells. Management periodically reviews the estimate of the timing of the wells’ closure as well as the estimated closing costs, discounted at the credit adjusted risk free rate of 12%. Quarterly, management accretes the 12% discount into the liability and makes other adjustments to the liability for well retirements incurred during the period.

 

Recent Accounting Pronouncements

 

In December 2004, the FASB published Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), (SFAS 123(R)) “Share Based Payment”. SFAS 123(R) established standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123(R) eliminated the ability to account for share-based compensation transactions using APB Opinion No. 25 (APB 25), “Accounting for Stock Issued to Employees”, and generally required that such transactions be accounted for using a fair-value-based method. This statement is effective for fiscal years beginning after June 15, 2005. SFAS 123(R) applies to all awards granted after the required effective date and to awards modified, repurchased, or cancelled after that date and as a consequence future employee stock option grants and other stock based compensation plans will be recorded as expense over the vesting period of the award based on their fair values at the date the stock based compensation is granted. The cumulative effect of initially applying SFAS 123(R) is to be recognized as of the required effective date using a modified prospective method. Under the modified prospective method the Company recognized stock-based compensation expense from July 1, 2005 as if the fair value based accounting method had been used to account for all outstanding unvested employee awards granted, modified or settled in prior years. The Company adopted SFAS 123(R) in 2005 and recognized $84,030 in compensation expense for options granted in 2005 and $128,197 in 2006. The Company will recognize $141,524 in 2007 and 2008 in compensation expense relating to those options granted in 2005. The ultimate impact on future years results of operation and financial position will depend upon the level of stock based compensation granted in future years.

 

In July 2006, the FASB issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement 109" ("FIN 48"), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is "more-likely-than-not" to be sustained if the position were to be

 

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challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the "more-likely-than-not" threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on January 1, 2007. We are currently evaluating the impact of adopting FIN 48 and do not expect the interpretation will have a material impact on our results of operations or financial position.

 

CONTRACTUAL OBLIGATIONS

 

The following table summarizes the Company’s contractual obligations at December 31, 2006:

Payments Due By Period

 

 

 

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 $51.74 per barrel to a high of $68.82 per barrel during 2006. Gas price realizations ranged from a monthly low of $4.20 per Mcf to a monthly high of $11.55 per Mcf during the same period. The Company did not enter into any hedging agreements in 2006 to limit exposure to oil and gas price fluctuations.

 

_________________________

   

 

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Interest Rate Risk

 

At December 31, 2006, the Company had debt outstanding of approximately $2,795,801 including, as of that date, $2,600,000 owed on its credit facility with Citibank Texas, N. A. The interest rate on the Citibank credit facility is variable at a rate equal to LIBOR plus 2.5%. The Company’s remaining debt of $195,801 has fixed interest rates ranging from 5.5% to 8.25%. As a result, the Company's annual interest costs in 2006 fluctuated based on short-term interest rates on approximately 93% of its total debt outstanding at December 31, 2006. The impact on interest expense and the Company’s cash flows of a 10 percent increase in the interest rate on the Citibank Credit facility would be approximately $21,128, assuming borrowed amounts under the Citibank credit facility remained at the same amount owed as of December 31, 2006. The Company did not have any open derivative contracts relating to interest rates at December 31, 2006.

 

Forward-Looking Statements And Risk

 

Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company's control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil 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.

 

 

 

ON ACCOUNTING AND FINANCIAL DISCLOSURE

 

On May 31, 2005, the Company engaged Rodefer Moss & Co, PLLC (“Rodefer Moss”) of Knoxville, Tennessee to serve as its independent registered public accounting firm and dismissed BDO Seidman LLP (“BDO”). The change in independent registered public accounting firms was approved by the Audit Committee of the Company’s Board of Directors and reported on a Current Report on Form 8-K, dated June 6, 2005. BDO audited the Company’s financial

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statements for the year ended December 31, 2004 and for several prior years, and Rodefer Moss audited the financial statements for the year ended December 31, 2005 as well as the current fiscal year ended December 31, 2006.

 

The Company provided its former accountants, BDO Seidman, LLP with a copy of the 8-K Report referred to above and requested that BDO furnish it with a letter addressed to the SEC stating whether or not it agreed with the statements set forth in that Report regarding BDO. BDO provided the Company with a copy of the letter it sent to the SEC stating that it had reviewed the disclosure provided in the 8-K Report and it agreed with the statements in that Report regarding BDO Seidman, LLP.

 

Prior to engaging Rodefer Moss as its new independent auditors, the Company did not consult with Rodefer Moss regarding (i) the application of accounting principles to a specified transaction, either completed or proposed; (ii) the type of audit opinion that might be rendered by Rodefer Moss on the Company’s financial statements; or (iii) any other matter that was the subject of a disagreement between the Company and its former auditors as described in Item 304(a)(1)(iv) of Regulation S-K or a reportable event as that term is defined in Item 304(a)(1)(v).

 

 

Evaluation of Disclosure Controls and Procedures

 

The Company’s Chief Executive Officer and Principal Financial Officer, and other members of management team have evaluated the effectiveness of the Company’s disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)). Based on such evaluation, the Company’s Chief Executive Officer and Principal Financial Officer have concluded that the Company’s disclosure controls and procedures, as of the end of

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the period covered by this Report, were adequate and effective to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act, is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

 

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

 

Changes in Internal Controls

 

There have been no changes to the Company’s system of internal control over financial reporting during the quarter ended December 31, 2006 that has materially affected, or is reasonably likely to materially affect, the Company’s system of controls over financial reporting.

 

As part of a continuing effort to improve the Company’s business processes management is evaluating its internal controls and may update certain controls to accommodate any modifications to its business processes or accounting procedures.

 

 

PART III

 

Certain information required by Part III of this Report is incorporated by reference from the Company’s definitive proxy statement to be filed with the SEC in connection with the solicitation of proxies for the Company’s 2007 Annual Meeting of Stockholders (the “Proxy Statement”).

 

 

The information required by this Item with respect to the Company’s directors is incorporated by reference to the information in the section entitled “Proposal No. 1: Election of Directors” in the Proxy Statement.

 

The information required by this Item with respect to corporate governance regarding the Nominating Committee and Audit Committee of the Board of Directors is incorporated by reference from the section entitled “Board of Directors - Committees” in the Proxy Statement.

 

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                              The information required by this Item with respect to disclosure of any known late filing or failure by an insider to file a report required by Section 16 of the Exchange Act is incorporated by reference to the information in the section entitled “Section 16(a) Beneficial Ownership Reporting Compliance” in the Proxy Statement.

 

The information required by this Item with respect to the identification and background of the Company’s executive officers and the Company’s code of ethics is set forth in Item 1 of this Report.

 

 

The information required by this Item is incorporated by reference from the information in the sections entitled “Executive Compensation”, “Compensation/Stock Option Committee Interlocking and Insider Participation” and “Compensation Committee Report” in the Proxy Statement.

 

 

Except as set forth below, the information required by this Item regarding security ownership of certain beneficial owners and directors and officers is incorporated by reference from the sections entitled “Voting Securities and Principal Holders” and “Beneficial Ownership of Directors and Officers” in the Proxy Statement.

 

Equity Compensation Plan Information

 

The following table sets forth information regarding the Company’s equity compensation plans as of December 31, 2006.

 

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The information required by this Item as to transactions between the Company and related persons is incorporated by reference from the section entitled “Certain Transactions” in the Proxy Statement.

 

The information required by this Item as to the independence of the Company’s directors and members of the committees of the Company’s Board of Directors is incorporated by reference from the section entitled “Board of Directors” and the subsections thereunder entitled “Director Independence” and “Committees” set forth in “Proposal No. 1: Election of Directors” in the Proxy Statement.

 

_________________________

¹³             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 to 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 an amendment to the Plan to increase the aggregate number of shares that may be issued under the Plan from 1,000,000 shares to 3,500,000 shares.

 

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The information required by this Item is incorporated by reference from the information in the section entitled “Proposal No. 2: Ratification of Selection of Rodefer Moss & Co, PLLC as Independent Auditors” in the Proxy Statement.

 

PART IV

 

 

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

 

1. Financial Statements:

 

 

2. Financial Schedules:

 

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

3. Exhibits.

 

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

 

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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 27, 2007

 

 

 

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.

 

 

 

 

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