Item 1. Business
Item 1A.
ITEM 1A.
RISK FACTORS
In addition to the other information included in this Form 10-K, the following risk factors should be considered in evaluating the Company’s business and future prospects. The risk factors described below are not 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.
The Company has a History of Significant Losses.
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 $26,645,810 as of December 31, 2007. 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, 2006, and 2007. 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 Sovereign Bank Is Subject to Variable Rates of Interest,
Which Could Negatively Impact the Company.
Borrowings under the Company’s credit facility with Sovereign Bank of Dallas, Texas (“Sovereign Bank”) are at variable rates of interest and expose the Company to interest rate risk. If interest rates increase, the Company’s debt service obligations on the variable rate indebtedness would increase even though the amount borrowed remained the same, and 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, Sovereign Bank may choose to require repayment of the outstanding borrowings sooner than currently required by the agreement.
The Company’s Borrowing Base under its Credit Facility may be reduced by Sovereign Bank.
The borrowing base under the Company’s revolving credit facility with Sovereign Bank will be determined from time to time by the lender, consistent with its customary natural gas and crude oil lending practices. Reductions in estimates of the Company’s natural gas and crude oil reserves could result in a reduction in the Company’s borrowing base, which would reduce the amount of financial resources available under the Company’s revolving credit facility to meet its capital requirements. Such a reduction could be the result of lower commodity prices or production, inability to drill or unfavorable drilling results, changes in natural gas and crude oil reserve engineering, the lenders' inability to agree to an adequate borrowing base or adverse changes in the lenders' practices regarding estimation of reserves. If cash flow from operations or the Company’s borrowing base decrease for any reason, the Company’s ability to undertake exploration and development activities could be adversely affected. As a result, the Company’s ability to replace production may be limited. In addition, if the borrowing base under the Company’s Sovereign Bank revolving credit facility is reduced, it would be required to pay down its borrowings under the revolving credit facility so that outstanding borrowings do not exceed the reduced borrowing base. This could further reduce the cash available to the Company for capital spending and, if the Company did not have sufficient capital to reduce its borrowing
level, could cause the Company to default under its revolving credit facility with Sovereign Bank.
Declines In Oil or Gas Prices Will Materially Adversely Affect the Company’s Revenues.
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. Although oil prices are currently at record high levels which has had a substantial favorable impact on the Company’s revenues, there can be no assurances that prices will remain at the current rates or continue to increase as they have during the past year. 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.
Risks In Rates Of Oil and Gas Production, Development Expenditures, and Cash Flows May
Have a Substantial Impact on the Company’s Finances.
Projecting the effects of commodity prices on production, and timing of development expenditures include many factors beyond the Company’s control. The future estimates of net cash flows from the Company’s proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates which would have a significant impact on the Company’s financial position.
The Company’s Oil and Gas Operations Involve Substantial Costs and are
Subjectto Various Economic Risks.
The Company’s oil and gas 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.
Shortages of Oil Field Equipment, Services and Qualified Personnel Could Adversely
Affect the Company’s Results of Operations.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. The Company does not own any drilling rigs and is dependent upon third parties to obtain and provide such equipment as needed for the Company’s drilling activities. There have also been shortages of drilling rigs and other equipment as oil prices have risen 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.
The Company’s Failure to Find or Acquire Additional Reserves Will Result in the Decline of the
Company’s Reserves Materially From Their Current Levels.
The rate of production from the Company’s Kansas oil and Tennessee oil and natural gas properties generally declines as reserves are depleted. Except to the extent that the Company 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 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 Reserve Estimates May Be Subject
to Other Material Downward Revisions.
The Company’s oil reserve estimates or gas reserve estimates may be subject to material downward revisions for additional reasons other than the factors mentioned in the previous risk factor entitled “The Company’s Failure to Find or Acquire Additional Reserves Will Result in the Decline of the Company’s Reserves Materially from Their Current Levels.” While the future estimates of net cash flows from the Company’s proved reserves and their present value are based upon assumptions about future production levels, prices, and costs that may prove to be incorrect over time, those same assumptions, whether or not they prove to be correct, may cause the Company to make drilling or developmental decisions that will result in some or all of the Company’s proved reserves to be removed from time to time from the proved reserve categories previously reported by the Company. This may occur because economic expectations or forecasts, together with the Company’s limited resources, may cause the Company to determine that drilling or development of certain of its properties may be delayed or may not foreseeably occur, and as a result of such decisions any category of proved reserves relating to those yet undrilled or undeveloped properties may be removed from the Company’s reported proved reserves. Consequently, the Company’s proved reserves of oil or of gas, or both, may be materially revised downward from time to time. As an example, the Company’s proved Swan Creek gas reserves have been revised downward in the past few years as a result of removal of portions of the Company’s reported gas reserves from the “proved undeveloped category (“PUD”) and the “proved developed nonproducing” (“PDNP”) categories because of the Company’s determination that additional drilling or development of Swan Creek may not occur in the foreseeable future based on the Company’s determination that the economic returns from such drilling or development would not be favorable when compared to the costs and anticipated results of such activity. Although that particular revision at this time will not have a significant impact on overall results of operations in view of the relatively small portion of the Company’s current business and assets founded in natural gas (as opposed to oil where reserves have been materially revised upward in the same period), other revisions in gas reserves, or in oil reserves, in the future may be significant and materially reduce oil or gas reserves. In addition, the Company may elect to sell some or all of its oil or gas reserves in the normal course of the Company’s
business. Any such sale would result in all categories of those proved oil or gas reserves that were sold no longer being reported by the Company.
There is Risk that the Company may be Required to Write-Down the Carrying
Value of its Natural Gas and Crude Oil Properties.
The Company uses the full cost method to account for its natural gas and crude oil operations. Accordingly, the Company capitalizes the cost to acquire, explore for and develop natural gas and crude oil properties. Under full cost accounting rules, the net capitalized cost of natural gas and crude oil properties may not exceed a "ceiling limit" which is based upon the present value of estimated future net cash flows from proved reserves, discounted at 10%. If net capitalized costs of natural gas and crude oil properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings. This is called a "ceiling limitation write-down." This charge does not impact cash flow from operating activities, but does reduce the Company’s stockholders' equity and earnings. The risk that the Company will be required to write-down the carrying value of natural gas and crude oil properties increases when natural gas and crude oil prices are low. In addition, write-downs may occur if the Company experiences substantial downward adjustments to its estimated proved reserves. An expense recorded in one period may not be reversed in a subsequent period even though higher natural gas and crude oil prices may have increased the ceiling applicable to the subsequent period. The Company has not incurred ceiling limitation write-downs in the past. However, we cannot assure you that the Company will not experience ceiling limitation write-downs in the future.
Use of the Company’s Net Operating Loss Carryforwards may be limited.
At December 31, 2007, The Company had, subject to the limitations discussed in this risk factor, substantial amounts of Net Operating Loss Carryforwards for U.S. federal income tax purposes. These loss carryforwards will eventually expire if not utilized. In addition, as to a portion of the U.S. net operating loss carryforwards, the amount of such carryforwards that the Company can use annually is limited under U.S. tax laws. Uncertainties exist as to both the calculation of the appropropiate deferred tax assets based upon the existence of these loss carryforwards, as well as the future utilization of the operating loss carryforwards under the criteria set forth under FASB Statement No. 109. In addition, limitations exist upon use of these carryforwards in the event of a change in control of the Company occurs. There are risks that the Company may not be able to utilize some or all of the remaining carryforwards, or that deferred tax assets that were previously booked based upon such carryforwards may be written down or reversed based on future economic factors that may be experienced by the Company. The effect of such writedowns or reversals, if they occur, may be material and substantially adverse.
The Company has Significant Costs to Conform to
Government Regulation of the Oil and Gas Industry.
The Company’s exploration, production, and marketing operations are regulated extensively at the federal, state and local levels. The Company is currently in compliance with these regulations. In order to maintain its compliance, the Company has made and will have to continue to make substantial expenditures in its efforts to comply with the requirements of environmental and other regulations. Further, the oil and gas regulatory environment could change in ways that might substantially increase these costs. Hydrocarbon-producing states regulate conservation practices and the protection of correlative rights. These regulations affect the Company’s operations and limit the quantity of hydrocarbons it may produce and sell. 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 also has Significant Costs Related to Environmental Matters.
The Company’s operations are also subject to numerous and frequently changing laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. The Company owns or leases, and has owned or leased, properties that have been leased for the exploration and production of oil and gas and these properties and the wastes disposed on these properties may be subject to the Comprehensive Environmental Response, Compensation and Liability Act, the Oil Pollution Act of 1990, the Resource Conservation and Recovery Act, the Federal Water Pollution Control Act and similar state laws. Under such laws, the Company could be required to remove or remediate wastes or property contamination.
Laws and regulations protecting the environment have generally become more stringent and, may in some cases, impose “strict liability” for environmental damage. Strict liability means that the Company may be held liable for damage without regard to whether it was negligent or otherwise at fault. Environmental laws and regulations may expose the Company to liability for the conduct of or conditions caused by others or for acts that were in compliance with all applicable laws at the time they were performed. Failure to comply with these laws and regulations may result in the imposition of administrative, civil and criminal penalties.
The Company’s ability to conduct continued operations is subject to satisfying applicable regulatory and permitting controls. The Company’s current permits and authorizations and ability to get future permits and authorizations may be susceptible, on a going forward basis, to increased scrutiny, greater complexity resulting in increased 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.
The Company is Not Competitive with
Respect to Acquisitions or Personnel.
The oil and gas business is highly competitive. In seeking any suitable oil and gas properties for acquisition, or drilling rig operators and related personnel and equipment, the
Company is a small entity with limited financial resources and may not be able to compete with most other companies, including large oil and gas companies and other independent operators with greater financial and technical resources and longer history and experience in property acquisition and operation.
The Company Depends on Key Personnel,
Whom it May Not be Able to Retain or Recruit.
Jeffrey R. Bailey, the Company’s Chief Executive Officer, other members of present management and certain Company employees have substantial expertise in the areas of endeavor presently conducted and to be engaged in by the Company. 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.
The Company’s Operations are Subject to Changes in the General Economic Conditions.
Virtually all of the Company's operations are subject to the risks and uncertainties of adverse changes in general economic conditions, the outcome of 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 Company’s Administrative Costs.
The Sarbanes-Oxley Act of 2002, as well as rules subsequently implemented by the SEC and listing requirements subsequently adopted by the 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 for the most part apply to the same extent as they apply to all major publicly traded companies. As a result, they have significantly increased the Company’s legal, financial, compliance and administrative costs, and have made certain other activities more time consuming and costly, as well as requiring substantial time and attention of our senior management. The Company expects its continued compliance with these and future rules and regulations to continue to require significant resources. These rules and regulations also may make it more difficult and more expensive for the Company to obtain director and officer liability insurance in the future, and could make it more difficult for it to attract and retain qualified members for the Company’s Board of Directors, particularly to serve on its audit committee.
The Company’s Chairman of the Board Beneficially 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, 2007, 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.
Shares Eligible for Future Sale may Depress the Company’s Stock Price.
As of March 3, 2008, the Company had 59,155,750 shares of common stock outstanding of which 21,654,879 shares were held by affiliates and, in addition, 2,841,000 shares of common stock were subject to outstanding options granted under the Tengasco, Inc. Stock Incentive Plan (of which 1,627,000 shares were vested at March 3, 2008).
All of the shares of common stock held by affiliates are restricted or controlled securities under Rule 144 promulgated under the Securities Act of 1933, as amended (the "Securities Act"). The shares of the common stock issuable upon exercise of the stock options have been registered under the Securities Act. Sales of shares of common stock under Rule 144 or another exemption under the Securities Act or pursuant to a registration statement could have a material adverse effect on the price of the common stock and could impair the Company’s ability to raise additional capital through the sale of equity securities.
Future Issuance of Additional Shares of the Company’s
Common Stock could cause Dilution of Ownership Interests and Adversely Affect Stock Price.
The Company may in the future issue previously authorized and unissued securities, resulting in the dilution of the ownership interests of its current stockholders. The Company is currently authorized to issue a total of 100,000,000 shares of common stock with such rights as determined by the Board of Directors. Of that amount, approximately 59 million shares have been issued. The potential issuance of the approximately 41 million remaining authorized but unissued shares of common stock may create downward pressure on the trading price of the Company’s common stock. The Company may also issue additional shares of its common stock or other securities that are convertible into or exercisable for common stock for capital raising or other business purposes. Future sales of substantial amounts of common stock,
or the perception that sales could occur, could have a material adverse effect on the price of the Company’s common stock.
The Company may Issue Shares of Preferred Stock
With Greater Rights than Common Stock.
Subject to the rules of The American Stock Exchange, the Company’s charter authorizes the board of directors to issue one or more series of preferred stock and set the terms of the preferred stock without seeking any further approval from holders of the Company’s common stock. Any preferred stock that is issued may rank ahead of the Company’s common stock in terms of dividends, priority and liquidation premiums and may have greater voting rights than the Company’s common stock.
ITEM 1B.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
ITEM 2.
ITEM 2.
PROPERTIES
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. The Company has leased office space in Houston, Texas for use by Patrick McInturff, a vice president of the Company, at a rental of $1,000 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 Company does not yet have production interest in Texas, but it is anticipated that an opportunity to participate in the properties the Company manages on behalf of Hoactzin Partners, L.P. will be available in the future.
The Kansas Properties as of December 31, 2007 contained 192 leases totaling 28,934 acres in the vicinity of Hays, Kansas. The increase in the total volume of acreage of the Company’s Kansas Properties from 27,837 acres at the end of 2006 is primarily due to the purchase of two producing leases, the Heyl and RJ Thyfault. The Company focused its drilling, development, and exploration activities in Kansas in 2007 on evaluation of older producing
properties, and those properties acquired in 2005 and 2006. Many 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.
Kansas as a whole is of major significance to the Company. The majority of the Company’s current reserve value, current production, revenue, and future development objectives are centered in the Company’s ongoing interests in Kansas. By using 3-D seismic evaluation on existing locations owned by the Company in Kansas, the Company has added and continues to add proven direct offset locations. As a result of recent higher commodity prices for its oil, the Company has been able to drill from cash flow and attract favorable drilling partner programs in which the Company retains not only a carried beginning interest but a higher-than-industry-standard reversionary interest. The Company expects to continue this mix of company drilling and program drilling depending primarily on future cash flow and future oil prices. Breaking down the Company’s assets in Kansas into individual leases produces no apparent stand out leases that appear to be stand-alone principal properties. As a whole, however, our collective central Kansas holdings (see map below) are of major significance and as a group the most materially important segment of the Company as demonstrated by the following facts during the year ending December 31, 2007:
• Kansas accounted for 91.4% of the Company’s revenue (i.e. $8,560,097 of $9,368,624.)
• Kansas accounted for 86% of the Company’s total production measured in BOE (Barrel of Oil Equivalent)
• Kansas contributes $14.791 million in value of future proven development locations as of year end 2007, compared to just $567,000 in Tennessee
• The Company’s focus in 2008 will be to continue with offset seismic development, and leasing activity in Kansas. As a result, the Company’s undeveloped location value and total number of locations are expected to grow.
The map below indicates the location of the Company’s top six valued leases in Kansas as of December 31, 2007.
The following tables indicate the production from the Company’s top six leases in 2007 as well as the reserve value of these leases as of December 31, 2007. By comparing these tables with the tables below showing the total production from the Kansas Properties in 2007 and the Company’s aggregate reserve value as of December 31, 2007, it is apparent that none of the Company’s Kansas leases are on their own significant properties, but that they must all be viewed as a whole to appreciate their significance to the Company’s operations.
Largest Kansas Leases by Production
Largest Kansas Lease by Reserve Value
Tennessee Properties
The Company's Swan Creek leases are on approximately 6,675 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 8,635 acres at the end of 2006 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
The Company’s estimated total net proved reserves of oil and natural gas as of December 31, 2007, and the present values of estimated future net revenues attributable to those reserves as of those dates, are presented in the following table. These estimates were prepared by LaRoche Petroleum Consultants, Ltd. (“LaRoche”) of Houston, Texas, and are part of their reserve reports on the Company’s oil and gas properties. LaRoche and its employees and its registered petroleum engineers have no interest in the Company and performed those services at their standard rates. Laroche’s estimates were based on a review of geologic, economic, ownership and engineering data that they were provided by the Company. In estimating the reserve quantities that are economically recoverable, end-of-period natural gas and oil prices, held constant, were used. In accordance with SEC regulations, no price or cost escalation or reduction was considered.
SEC regulations require that the natural gas and oil prices used in Laroche’s reserve reports are the period-end prices for natural gas and oil at December 31, 2007. These prices are held constant in accordance with SEC guidelines for the life of the wells included in the reserve reports but are adjusted by lease for energy content, quality, transportation, compression and gathering fees, and regional price differentials. The weighted average oil and natural gas prices after basis adjustments used in our reserve valuation as of December 31, 2007 were $85.44 per barrel and $7.21 per Mcf.
The prices used in calculating the estimated future net revenue attributable to proved reserves do not reflect market prices for natural gas and oil production sold subsequent to December 31, 2007. There can be no assurance that all of the estimated proved reserves will be produced and sold at the assumed prices. Accordingly, the foregoing prices should not be interpreted as a prediction of future prices.
The standardized measure of future net cash flows associated with total proved reserves as of December 31, 2007 is stated to be $53,627,086. The LaRoche Report indicates the “proven developed producing” reserves for the Company as of December 31, 2007 to be as follows: net production volumes of 1,604,607 barrels of oil and 1,130 MMCF of gas compared to 1,358,532 barrels of oil and 1,264 MMCF of gas as reported by the Company at the end of 2006. The standardized measure of future net cash flows associated with total proved producing reserves as of December 31, 2007 is stated to be $37,803,144. The increase in oil reserves from 2006 to 2007 is reflective of the Company’s increased drilling activities in Kansas in 2007 and future drilling plans including 39 future wells at proved undeveloped (PUD) locations. 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 drop in the price used to calculate the gas reserves from $8.33 per Mcf in 2006 to $7.21 per Mcf in 2007. For additional information concerning our estimated proved reserves, the standardized measure of discounted future net cash flows of the proved reserves at December 31, 2007, 2006 and 2005, and the changes in quantities and standardized measure of such reserves for each of the three years then ended; see Note 20 to our consolidated financial statements.
In substance, the LaRoche Report used estimates of oil and gas reserves based upon standard petroleum engineering methods which include production data, decline curve analysis, volumetric calculations, pressure history, analogy, various correlations and technical factors. Information for this purpose was obtained from owners of interests in the areas involved,
state regulatory agencies, commercial services, outside operators and files of LaRoche. 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., 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.
_________________________
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.
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.
10,818
183,400
$18.86
$53.90
$8.74
Oil and Gas Drilling Activities
In 2007, the Company drilled 16 new wells in Kansas, 15 of which were drilled in the third and fourth quarters. These wells included nine wells drilled in the Ten Well Program. The Company has a 100% working interest in the remaining seven wells drilled in Kansas in 2007. All wells drilled in 2007 have produced in the aggregate a cumulative total of 6,215 barrels of oil.
The results of the wells drilled in Kansas as of December 31, 2007 are set out in the following table. Unless otherwise indicated the Company has a 100% working interest in the wells.
NAME OF
WELL
DATE COMPLETED
CUMULATIVE PRODUCTION (Bbl)
Mai #1
2-18-07
Dry Hole - Plugged (exploratory)
Lowry B #1
5-22-07
Dry Hole - Plugged
Dirks #2
7-9-2007
749.00
Howard #1
7-5-07
Dry Hole - Plugged (exploratory)
Hobrock #5
8-7-2007
1817.00
Veverka #1
8-17-07
Dry Hole - Plugged
Gilliland #1
8-28-07
Dry Hole - Plugged (exploratory)
Stahl A #1
10-16-2007
795.00*
Croffoot AA #1
10-19-2007
1285.00*
Veverka A #1
11-16-2007
75.00*
Croffoot BB #1
11-15-2007
863.00*
Howard #2
11-8-07
Dry Hole - Plugged* (exploratory)
Nutsch #1
12-6-2007
631.00*
Green #1
12-27-2007
0* (Exploration Discovery)
Veverka A #2
1-4-2008
0*
McElaney #1
1-24-08
0*(Exploration Discovery)
The Company continues to pursue incremental production increases where possible in the older wells, by using recompletion techniques to enhance production from currently producing intervals.
In 2007, the Company did not drill any new wells in the Swan Creek Field. The Company has signed a farmout agreement allowing the drilling of shale gas wells in leased areas surrounding 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.
The following tables set forth for the fiscal years ending December 31, 2005, 2006, and 2007 the number of gross and net development wells drilled by the Company. The wells drilled in 2007 refer to the nine wells drilled in the Ten Well Program as well as seven 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, 2007. 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.
GAS
OIL
Gross
Net
Gross
Net
Kansas
Tennessee
16.3
3.5
Developed and Undeveloped Oil and Gas Acreage
As of December 31, 2007, the Company owned working interests in the following developed and undeveloped oil and gas acreage. Net acres refer to the Company’s interest less the interest of royalty and other working interest owners.
ITEM 3.
ITEM 3.
LEGAL PROCEEDINGS
The Company is not a party to any pending material legal proceeding. To the knowledge of management, no federal, state or local governmental agency is presently contemplating any proceeding against the Company, which would have a result materially adverse to the Company. To the knowledge of management, no director, executive officer or affiliate of the Company or owner of record or beneficially of more than 5% of the Company's common stock is a party adverse to the Company or has a material interest adverse to the Company in any proceeding.
PART II
Market Information
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, 2007 and December 31, 2006 are set forth below.
Holders
As of March 3, 2008 the number of shareholders of record of the Company's common stock was 333 and management believes that there are approximately 6,133 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 2007 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 2007, the Company issued 6,832 shares of its common stock pursuant to the exercise of warrants issued by the Company to a member 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 2007 were previously reported in Reports filed by the Company with the SEC.
Purchases of Equity Securities by the Company
And Affiliated Purchasers
Neither the Company nor any of its affiliates repurchased any of the Company’s equity securities during 2007.
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, 2002. The performance graph represents past performance and should not be considered to be an indication of future performance.
COMPARISON OF CUMULATIVE TOTAL RETURN OF ONE OR MORE
COMPANIES, PEER GROUPS, INDUSTRY INDEXES AND/OR BROAD MARKETS
ITEM 6.
SELECTED FINANCIAL DATA
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,
Income Statement Data:
Oil and Gas Revenues
$9,300,144
$8,896,036
$7,067,790
$6,013,374
$6,040,872
Production Cost and Taxes
$4,322,833
$3,287,233
$3,046,460
$3,364,429
$3,412,201
General and
Administrative
$1,417,001
$1,293,109
$1,322,616
$1,777,183
$1,486,280
Interest Expense
$ 333,198
$ 168,590
$ 472,655
$1,367,180
$1,120,738
Net Income/Loss
$3,510,322
$2,141,364
$1,088,028
$(1,994,025)
$(3,197,662)
Net Income/Loss Attributable to Common Stockholders
$3,510,322
$2,141,364
$1,088,028
$(1,994,025)
$(3,451,580)
Net Income/Loss Attributable to Common Stockholder Per Share
$ 0.06
$ 0.04
$ 0.02
$
(0.05)
$
(0.29)
Year Ended December 31,5,6
Balance Sheet Data:
Working Capital Surplus
(Deficit)
$ 2,473,4767
$872,507
$(1,334,744)
$(6,753,721)
$(10,822,717)
Oil and Gas Properties, Net
$13,209,601
$12,703,629
$ 9,675,977
$ 12,826,903
$12,989,443
Pipeline Facilities, Net
$12,916,667
$13,460,667
$13,994,453
$ 14,602,639
$15,139,789
Total Assets
$34,281,549
$28,454,338
$25,908,616
$ 28,209,749
$30,604,240
Long-Term Debt
$ 4,315,773
$ 2,730,534
$ 117,912
$ 1,940,890
$ 6,256,818
Redeemable
Preferred Stock
$ -0-
$ -0-
$ -0-
$ -0-
$ -0-
Stockholders Equity
$28,102,871
$24,420,205
$ 21,961,454
$18,349,687
$11,251,871
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
The Company incurred a net income to holders of common stock of $3,510,322 or $0.06 per share in 2007 compared to a net income of $2,141,364 or $0.04 per share in 2006 and compared to a net income of $1,088,028 or $0.02 per share in 2005. The Company recognized a tax benefit for net operating loss carry forwards in the amount of $2,100,000 in 2007.
The Company realized revenues of $9,368,624 in 2007 compared to $9,001,681 in 2006 and compared to $7,172,876 in 2005. Revenues increased $366,943 from 2006 due primarily to an increase in oil prices in Kansas; prices averaged $66.42 in 2007 and 60.84 in 2006. Gross oil production in 2007 was just slightly less than 2006 resulting from the loss of production in January 2007 due to the electricity outage during an ice storm. As a result of that storm, many counties in Kansas, including some counties where the Company has wells, lost power for the entire month of January. Producing wells in those counties were unable to produce without electricity to run the well pumps during the power outage. Consequently in January 2007 the Company saw production and revenue decline from monthly levels in late 2006. None of the Company’s producing wells were physically damaged by the ice storm or by non
_________________________
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.
The Company’s working capital surplus of 2,473.476 was attributable to high commodity prices as well as an increase in the borrowing base by $900,000 on December 17, 2007 and the funding of the Ten Well Program. The Company has expended approximately $1.5 million of these funds subsequent to year-end on the Methane Project and completing the Ten Well Program.
-
production during the absence of power, but the storm did substantially adversely impact production levels and sales in the first two months of 2007 while at the same time causing an increase in expenses. Eventually new poles and lines were rebuilt on a locally massive scale and electrical power was restored, and the Company experienced a rebound of production commencing in March 2007.
In 2007 the Company produced 178,311 barrels of oil in Kansas compared to 179,555 in 2006, a decrease of 1,244 barrels for the year. Additionally, the wells in the Eight Well Program (former Series “A”) reached the reversionary “flip point” in April 2007. This is the point at which the Company started receiving 85% of the participant’s interest plus our original interest of (19.3%) for an approximate total net interest to the Company equal to an 88% interest. In 2007 those wells produced 22,195 gross barrels of oil; the wells in the Twelve Well Program (former Series “B”) now converted to a six well program produced 15,864 gross barrels; wells polymered produced 19,502 barrels; and, the two new wells drilled produced 2,566 gross barrels in 2007. During 2007 the Company drilled 9 of the 10 wells in the Ten Well Program and produced 3,649 barrels from the 5 wells that were completed by year-end. The other three wells that were drilled in 2007 were then completed in 2008. In March 2008, the tenth and final well in the Ten Well Program was both drilled and completed as a producer. As of the date of this report, nine of ten wells drilled in the Ten Well Program have been completed as producers and are producing approximately 106 barrels per day. During the first half of 2008 the Company expects the reversionary flip point for the Twelve Well Program (former Series “B”) now converted to a six well program, to be achieved.
Gas prices received for sales of gas from the Swan Creek Field averaged $6.86 per Mcf in 2007, $7.27 per Mcf in 2006 and $8.74 per Mcf in 2005. Oil prices received for sales of oil from the Swan Creek field averaged $64.81 per barrel in 2007, and $60.39 per barrel in 2006, and. $53.90 per barrel in 2005.
Production costs and taxes in 2007 increased to $4,322,833 from $3,287,233 in 2006 and $3,046,460 in 2005. The difference is due to increased work-overs to increase production, increased taxes, and overall cost increases of supplies in the industry.
Depletion, depreciation, and amortization for 2007 was $1,631,468, a decrease from $1,911,416 in 2006 due to production volumes added to future reserves from drilling activities. Depletion, depreciation, and amortization increased to $1,911,416 in 2006 from $1,605,043 in 2005. The increase in 2006 was 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 Company’s general and administrative costs of $1,417,001 in 2007 remained generally consistent with 2006 levels of $1,293,109 and 2005 levels of $1,322,616. The 2007, 2006 and 2005 costs included non-cash charges related to stock options of $116,476, $159,160 and $103,400 respectively.
The increase in interest expense in 2007 relates to the borrowing base increase of the Citibank credit facility in 2007. Interest expense for 2006 decreased significantly over 2005 levels. This was due to the conversion of the Company’s preferred stock, which was subject to mandatory redemption, into either interest in a drilling program, common stock or cash payoffs. As of December 31, 2006, the Company’s only debt financing were vehicle loans totaling $195,801 and the CitiBank loan of $2,600,000.
The Company’s public relations costs remained stable at $21,605 for 2007, compared to $26,037 for 2006 and $30,020 for 2005 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 2007 were $232,197 compared to $173,932 in 2006. This was due to the Company commencing its review of its internal controls over its financial reporting in accordance with Item 308(T) of Regulation S-K. Professional fees in 2006 decreased from 2005 levels as the Company’s litigation was settled.
The Company recorded a deferred tax asset of $2,100,000 in 2007 relating to the Company’s net operating loss carry forwards. The Company recorded a gain on disposal of preferred stock of $655,746 in 2005.
Liquidity and Capital Resources
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 were 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 interest of approximately 8.2%. Interest only was 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.
The Company used $1.393 million of the proceeds of the $2.6 million loan from Citibank to exercise the Company’s option to repurchase from Hoactzin Partners, L.P. (“Hoactzin”), the Company’s obligation to drill for Hoactzin the final six wells of the Company’s Twelve Well Program. Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin. He is also the sole shareholder and controlling person of Dolphin Management, Inc., the general partner of Dolphin Offshore Partners, L.P., which is the Company’s largest shareholder. A detailed description of the Twelve Well Program is set forth In “Item 1 - Business” under the subheading “Kansas Drilling Programs”.
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. 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 was 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 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) as well as the Company’s earlier Eight Well Program (offered to the former Series A preferred stockholders).
Under the terms of the Eight Well Program and Twelve (now Six) Well program, 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 was reached in April 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 during the first half of 2008. It is anticipated, based upon current volumes and prices that this will result in an increase in revenues to the Company of approximately $50,000 per month.
On April 19, 2007 the Company borrowed an additional $700,000 from Citibank under the existing Citibank revolving credit facility. The additional borrowing resulted from Citibank’s increase in the Company’s borrowing base under the credit facility from $2.6 million to $3.3 million as a result of Citibank’s periodic borrowing base review conducted under the terms of credit facility. With the additional borrowing, the Company had borrowed the full amount of the $3.3 million borrowing base which was available to it under the Citibank revolving credit facility. Repayment of this additional sum was subject to the terms and conditions of the Citibank credit facility. The additional amount borrowed was used for additional development of the Company’s producing properties.
On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by the Company.
Under the facility as assigned to Sovereign, 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 $20 million or the Company’s borrowing base in effect from time to time. The Company’s initial borrowing base with Sovereign was set at $7.0 million, an increase from its borrowing base of $3.3 million with Citibank prior to the assignment.
The Company’s initial borrowing on December 17, 2007 under its new facility with Sovereign was approximately $4.2 million which will bear interest at a floating rate equal to prime as published in the Wall Street Journal plus 0.25% resulting in a current interest rate of
approximately 7.5%. Interest only is payable during the term of the loan and the principal balance of the loan is due December 31, 2010. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane Project assets.
The Company used a portion of the $4.2 million borrowed from Sovereign to pay off the funds it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign was used to pay bank fees and attorney fees relating to the assignment in the amount of approximately $75,000 and the balance of approximately $825,000 was used to pay a portion of the purchase price for equipment to be utilized in the Methane Project currently under construction in Church Hill, Tennessee by MMC, the Company’s wholly-owned subsidiary. See, “Item 1 - Business” under the subheading “The Methane Project”.
Net cash provided by operating activities for 2007 was $3,446,677 compared to net cash provided by operating activities of $4,353,966 in 2006. The Company’s net income in 2007 increased to $3,510,322 from $2,141,364 in 2006. The impact on cash provided by operating activities was due to the net income for 2007 and was increased by non-cash depletion, depreciation, and amortization of $1,631,468 and by non-cash compensation and services paid by insurance of equity instruments of $116,476. Cash flow provided in working capital items in 2007 was $211,742 compared to cash provided by working capital items of $122,152 in 2006. The Company’s net income for 2007 included a non-cash deferred tax asset for net operating loss carry forwards of $2,100,000.
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 $1,911,416 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 used in investing activities amounted to $3,145,764 for 2007 compared to net cash used in investment activities in the amount of $4,413,185 for 2006. The decrease in net cash used in investing activities during 2006 was primarily attributable to an increase in oil and gas properties of $5,190,611 offset by drilling program funds received of $3,850,000 and an increase in additions to methane project of $1,649,710.
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 financing activities increased to $1,556,261 in 2007 from cash provided by financing activities of $167,915 in 2006. In 2007 the primary sources of financing included proceeds from borrowings of $1,687,236 compared to $2,732,145 in 2006. The primary use of cash in financing activities in 2006 was to repay the drilling program liability of $2,324,400.
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.
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.
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 2007, 2006 or 2005.
Oil and Gas Reserves/Depletion Depreciation
And Amortization of Oil and Gas Properties
The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated 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, 2007 were determined by LaRoche Petroleum Consultants, Ltd. Projecting the effects of commodity prices on production, and timing of development expenditures includes many factors beyond the Company’s control. The future estimates of net cash flows from the Company’s proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates.
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 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 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, the Company adopted FIN 48 on January 1, 2007. The Company does not expect the interpretation will have an impact on its results of operations or financial position.
In September 2006, the Securities and Exchange Commission staff published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The Company adopted SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. It defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurement. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. It clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company continues to evaluate the impact the adoption of this statement could have on its financial condition, results of operations and cash flows.
In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities - As amended” (“SFAS 159”). SFAS 159 permits entities to elect to report eligible financial instruments at fair value subject to conditions stated in the pronouncement including adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial reporting by mitigating volatility in earnings related to current reporting requirements. The Company is considering the applicability of SFAS 159 and will determine if
adoption is appropriate. The effective date for SFAS 159 is for fiscal years beginning after November 15, 2007.
CONTRACTUAL OBLIGATIONS
The following table summarizes the Company’s contractual obligations at December 31, 2007:
Payments Due By Period
Contractual Obligations
Total
Less than
1year
1-3
years
3-5
years
More than
5 years
Long-Term Debt Obligations8
$4,373,660
57,887
$4,315,773
$-0-
$-0-
Capital Lease Obligations
$-0-
$-0-
$-0-
$-0-
$-0-
Operating Lease Obligations9
$31,673
$31,673
$-0-
$-0-
$-0-
Purchase Obligations
$-0-
$-0-
$-0-
$-0-
$-0-
Other Long-Term Liabilities
$-0-
$-0-
$-0-
$-0-
$-0-
Total
$4,405,333
$89,560
$4,315,773
$-0-
$-0-
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
Commodity Risk
The Company's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue. Monthly oil price realizations ranged from a low of $49.05 per barrel to a high of $89.18 per barrel during 2007. Gas price realizations ranged from a monthly low of $5.43 per Mcf to a monthly high of $7.59 per Mcf during the same period. The Company did not enter into any hedging agreements in 2007 to limit exposure to oil and gas price fluctuations.
_________________________
Interest Rate Risk
At December 31, 2007, the Company had debt outstanding of approximately $4,373,660 including, as of that date, $4,200,000 owed on its credit facility with Citibank Texas, N. A., which was assigned on December 17, 2007 to Sovereign Bank. The interest rate on the credit facility is variable at a rate equal to LIBOR plus 2.5%. The Company’s remaining debt of $173,660 has fixed interest rates ranging from 5.5% to 8.25%. As a result, the Company's annual interest costs in 2007 fluctuated based on short-term interest rates on approximately 96% of its total debt outstanding at December 31, 2007. The impact on interest expense and the Company’s cash flows of a 10 percent increase in the interest rate on the Sovereign Bank credit facility would be approximately $29,400, assuming borrowed amounts under the credit facility remained at the same amount owed as of December 31, 2007. The Company did not have any open derivative contracts relating to interest rates at December 31, 2007.
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.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A (T).
CONTROLS AND PROCEDURES
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 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.
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). Internal control over financial reporting refers to the process designed by, or under the supervision of, the Company’s Chief Executive Officer and Chief Financial Officer, and effected by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:
•
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company’s assets;
•
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of the Company’s management and directors; and
•
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements.
Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007 as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, the Company’s management used the criteria set forth in the framework in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring organizations of the Treadway Commission (“COSO”). Based on the evaluation conducted under the framework in “Internal Control - Integrated Framework,” issued by COSO the Company’s management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.
This report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit the Company to provide only management’s report in this Annual Report on Form 10-K.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Changes in Internal Controls
There have been no changes to the Company’s system of internal control over financial reporting during the year ended December 31, 2007 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.
ITEM 9B.
OTHER INFORMATION
The Company’s 2008 Annual Meeting of Stockholders will be held on June 2, 2008 at 9:00 a.m. at the Homewood Suites by Hilton, 10935 Turkey Drive, Knoxville, Tennessee 37922. Proposals of stockholders sought to be presented at the 2008 annual meeting must be received in writing, by the Chief Executive Officer of the Company at the Company’s offices by
the close of business on April 4, 2008 in order to be considered for inclusion in the Company's proxy statement relating to that meeting.
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 2008 Annual Meeting of Stockholders (the “Proxy Statement”).
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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.
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.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
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, 2007.
Plan Category
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
(a)
Weighted-average
exercise price of
outstanding, options,
warrants and rights
(b)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
(c)
Equity compensation
plans approved by
security holders
2,441,000
$0.30
39,368
Equity compensation
plans not approved
by security holders10
n/a
Total
2,441,000
$0.30
39,638
_________________________
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. On February 1, 2008, the Company’s Board of Directors adopted further amendments to the Plan to increase the number of shares that may be issued under the Plan by 3,500,000 shares and to extend the Plan for another 10 years from October 24, 2010 to October 24, 2020. The Company’s shareholders will be requested to vote to approve these amendments at the upcoming Annual Meeting of the Company’s shareholders to be held on June 2, 2008.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
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.
ITEM 14.
PRINCIPAL ACCOUNTANTS FEES AND SERVICES
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
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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:
Exhibit Number
Description
3.1
Charter (Incorporated by reference to Exhibit 3.7 to the registrant’s registration statement on Form 10-SB filed August 7, 1997 (the “Form 10-SB”))
3.2
Articles of Merger and Plan of Merger (taking into account the formation of the Tennessee wholly-owned subsidiary for the purpose of changing the Company’s domicile and effecting reverse split) (Incorporated by reference to Exhibit 3.8 to the Form 10-SB)
3.3
Articles of Amendment to the Charter dated June 24, 1998 (Incorporated by reference to Exhibit 3.9 to the registrant’s annual report on Form 10-KSB filed April 15, 1999 (the “1998 Form 10-KSB”))
3.4
Articles of Amendment to the Charter dated October 30, 1998 (Incorporated by reference to Exhibit 3.10 to the 1998 Form 10-KSB)
3.5
Articles of Amendment to the Charter filed March 17, 2000 (Incorporated by reference to Exhibit 3.11 to the registrant’s annual report on Form 10-KSB filed April 14, 2000 (the “1999 Form 10-KSB”))
3.6
By-laws (Incorporated by reference to Exhibit 3.2 to the Form 10-SB)
3.7
Amendment and Restated By-laws dated May 19, 2005 (Incorporated by reference to the registrant’s annual report on Form 10-K for the year ended December 31, 2005)
4.1
Form of Rights Certificate Incorporated by reference to registrant’s statement on Form S-1 filed February 13, 2004 Registration File No. 333-109784 (the “Form S-1")
10.1
Natural Gas Sales Agreement dated November 18, 1999 between Tengasco, Inc. and Eastman Chemical Company (Incorporated by reference to Exhibit 10.10 to the registrant’s current report on Form 8-K filed November 23, 1999)
10.2
Amendment Agreement between Eastman Chemical Company and Tengasco, Inc. dated March 27, 2000 (Incorporated by reference to Exhibit 10.14 to the registrant’s 1999 Form 10-KSB)
10.3
Natural Gas Sales Agreement between Tengasco, Inc. and BAE SYSTEMS Ordnance Systems Inc. dated March 30, 2001 (Incorporated by reference to Exhibit 10.20 to the 2000 Form 10-KSB)
10.4
Tengasco, Inc. Incentive Stock Plan (Incorporated by reference to Exhibit 4.1 to the registrant’s registration statement on Form S-8 filed October 26, 2000)
10.5
Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated May 18, 2004 in the principal amount of $2,500,000 (Incorporated by reference to Exhibit 10.47 to the registrant’s quarterly report on Form 10-Q filed May 20, 2004)
10.6
Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated December 30, 2004 in the principal amount of $550,000 (Incorporated by reference from to Exhibit 10.19 to the registrant’s Annual Report on Form 10-K filed March 31, 2005)
10.7
Asset Purchase Agreement dated March 4, 2005 between Tengasco, Inc. and Bear Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 the registrant’s current report on Form 8-K dated March 9, 2005 (the “March 9, 2005 Form 8-K”)
10.8
Assignment and Bill of Sale between Tengasco, Inc. and Bear Petroleum, Inc. (Incorporated by reference to Exhibit 10.2 to the March 9, 2005 Form 8-K)
10.9
Amended and Restated Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated May 19, 2005 in the principal amount of $700,000 ((Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated May 23, 2005)
10.10
Amendment to the Tengasco, Inc. Stock Incentive Plan dated May 19, 2005 (Incorporated by reference to Exhibit 4.2 to the registrant’s registration statement on Form S-8 filed June 3, 2005)
10.11
Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated August 22, 2005 in the principal amount of $1,814,000 (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated August 22, 2005 (the “August 22, 2005 8-K”))
10.12
Amended and Restated Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation dated August 18, 2005 in the principal amount of $700,000 (Incorporated by reference to Exhibit 10.2 to the August 22, 2005 8-K.)
10.13
Subscription Agreement of Hoactzin Partners, L.P. for a 94.275% working interest in the Company’s twelve well drilling program on its Kansas Properties. (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated October 5, 2005)
10.14
Loan and Security Agreement dated as of June 29, 2006 between Tengasco, Inc. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated June 29, 2006)
10.15*
Subscription Agreement of Hoactzin Partners, L.P. for the Company’s ten well drilling program on its Kansas Properties dated August 3, 2007.
10.16*
Agreement and Conveyance of Net Profits Interest dated September 17, 2007 between Manufactured Methane Corporation as Grantor and Hoactzin Partners, LP as Grantee.
10.17*
Agreement for Conditional Option for Exchange of Net Profits Interest for Convertible Preferred Stock dated September 17, 2007 between Tengasco, Inc., as Grantor and Hoactzin Partners, L.P., as Grantee.
10.18*
Assignment of Notes and Liens Dated December 17, 2007 between Citibank, N.A., as Assignor, Sovereign Bank, as Assignee and Tengasco, Inc., Tengasco Land & Mineral Corporation and Tengasco Pipeline Corporation as Debtors
10.19
Employment Agreement dated December 18, 2007 between Tengasco, Inc. and Charles Patrick McInturff (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated December 18, 2007)
10.20*
Management Agreement dated December 18, 2007 between Tengasco, Inc. and Hoactzin Partners, L.P.
Code of Ethics (Incorporated by reference to Exhibit 14 to the registrant’s annual report on Form 10-K filed March 30, 2004)
17.1
Letter of resignation of Clarke H. Bailey as a Director of the Company dated March 27, 2007 (Incorporated by reference to Exhibit 17.1 to the registrant’s current report on Form 8-K dated March 27, 2007)
21*
List of subsidiaries
23.1*
Consent of LaRoche Petroleum Consultants, Ltd.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a)
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a)
32.1*
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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 31, 2008
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in their capacities and on the dates indicated.
Signature
Title
Date
s/Jeffrey R. Bailey
Jeffrey R. Bailey
Director;
Chief Executive Officer
March 31 , 2008
s/Matthew K. Behrent
Matthew K. Behrent
Director
March 31, 2008
s/John A. Clendening
John A. Clendening
Director
March 31, 2008
s/Carlos P. Salas
Carlos P. Salas
Director
March 31, 2008
s/Peter E. Salas
Peter E. Salas
Director
March 31, 2008
s/Mark A. Ruth
Mark A. Ruth
Principal and Financial
Accounting Officer
March 31, 2008
Consolidated Financial Statements
Years Ended December 31, 2007, 2006 and 2005
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Consolidated Balance Sheets
-
Consolidated Income Statements
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Tengasco, Inc. and Subsidiaries
Knoxville, Tennessee
We have audited the accompanying consolidated balance sheets of Tengasco, Inc. and Subsidiaries as of December 31, 2007 and 2006 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Tengasco, Inc. and Subsidiaries as of December 31, 2007 and 2006 and the results of their operations and cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.
/s/ Rodefer Moss & Co, PLLC
Knoxville, Tennessee
March 27, 2008
Tengasco, Inc. and Subsidiaries
Consolidated Balance Sheets
December 31,
Assets
Current
Cash and cash equivalents
$ 2,226,839
$ 369,665
Accounts receivable
1,057,148
719,840
Participant receivables
49,872
13,008
Inventory
460,365
550,522
Other current assets
11,056
11,056
Total current assets
3,805,280
1,664,091
Restricted cash
120,500
120,500
Loan fees
223,733
237,738
Oil and gas properties, net (on the basis
of full cost accounting)
13,209,601
12,703,629
Pipeline facilities, net of accumulated
depreciation of $3,423,099 and $2,879,099
12,916,667
13,460,667
Other property and equipment, net
256,058
267,713
Deferred Tax Asset
2,100,000
-
Methane Project
1,649,710
-
$ 34,281,549
$ 28,454,338
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Balance Sheets
December 31,
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long term debt
$ 57,887
$ 65,267
Accounts payable
903,238
687,475
Accrued interest payable
10,005
8,432
Other accrued liabilities
360,674
30,410
Total current liabilities
1,331,804
791,584
Asset retirement obligations
531,101
512,015
Long term debt, less currentmaturities
4,315,773
2,730,534
Total liabilities
6,178,678
4,034,133
Stockholders’ equity
Common stock, $.001 par value; authorized 100,000,000 shares;
59,155,750 and 59,003,284 shares issued and outstanding
59,156
59,004
Additional paid-in capital
54,689,525
54,517,333
Accumulated deficit
(26,645,810)
(30,156,132)
Total Stockholders’ equity
28,102,871
24,420,205
$ 34,281,549
$ 28,454,338
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Income Statements
Years ended December 31,
Revenues and other income
Oil and gas revenues
$ 9,300,144
$ 8,896,036
$ 7,076,790
Pipeline transportation revenues
51,492
87,822
94,911
Interest Income
16,988
17,823
1,175
Total revenues and other income
9,368,624
9,001,681
7,172,876
Costs and expenses
Production costs and taxes
4,322,833
3,287,233
3,046,460
Depreciation, depletion and amortization
1,631,468
1,911,416
1,605,043
General and administrative
1,417,001
1,293,109
1,322,616
Interest expense
333,198
168,590
472,655
Public relations
21,605
26,037
30,020
Professional fees
232,197
173,932
263,800
Total costs and expenses
7,958,302
6,860,317
6,740,594
Net Operating Income
1,410,322
2,141,364
432,282
Deferred Tax Benefit
2,100,000
-
-
Gain on Preferred Stock
-
-
655,746
Net Income
$ 3,510,322
$ 2,141,364
$ 1,088,028
Net Income per share
Basic and diluted:
Operations
$ 0.06
$ 0.04
$ 0.02
Total
$ 0.06
$ 0.04
$ 0.02
Shares used in computing earnings per share
Basic
59,117,176
58,851,883
52,019,051
Diluted
60,827,224
60,364,797
52,659,051
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(1.)
Summary of Significant Accounting Policies
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, later changed to Onasco Companies, Inc. In 1995, the Company changed its name from Onasco Companies, Inc. to Tengasco, Inc., by merging into Tengasco, Inc., a Tennessee corporation, formed by the Company solely for this purpose.
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. Emphasis is also placed on pipeline and other infrastructure facilities to provide transportation services. The Company utilizes seismic technology to improve the recovery 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 2007, the Kansas Properties produced an average of 14,860 gross barrels of oil per month.
The Company’s activities in 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 2007, the Company produced an average of 347 thousand cubic feet of natural gas per day and 573 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 treatment technologies for the extraction of methane gas from nonconventional sources for delivery through the nation’s existing natural gas pipeline system, including the Company’s TPC pipeline system in Tennessee for eventual sale to natural gas customers.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Basis of Presentation
The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America, which contemplate continuation of the Company as a going concern and assume realization of assets and the satisfaction of liabilities in the normal course of business.
The consolidated financial statements include the accounts of the Company, Tengasco Pipeline Corporation, Tennessee Land & Mineral Corporation and Manufactured Methane Corporation. All intercompany balances and transactions have been eliminated.
Use of Estimates
The accompanying consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The actual results could differ from those estimates.
Revenue Recognition
The Company uses the sales method of accounting for natural gas and oil revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. Natural gas meters are placed at the customers’ locations and usage is billed monthly.
Cash and Cash Equivalents
The Company considers all investments with a maturity of three months or less when purchased to be cash equivalents.
Inventory
Inventory consists of crude oil in tanks and is carried at lower of cost or market value.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Oil and Gas Properties
The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all productive and nonproductive 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, delay rentals and the costs of drilling, completing, equipping and plugging oil and gas wells. 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 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 Company currently has $3,110,768 in unevaluated properties as of December 31, 2007. 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 has determined its reserves based upon reserve reports provided by Ryder Scott Company, Petroleum Consultants in 2005 , and by LaRoche Petroleum Consultants Ltd. in 2006 and 2007.
The capitalized oil and gas properties, 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. The Company has adopted an SEC accepted method of calculating the full cost ceiling test whereby the liability recognized under Statement of Financial Accounting Standard No. 143 (“SFAS”) “Accounting for Asset Retirement Obligation” (“SFAS 143”) is netted against property cost and the future abandonment obligations are included in estimated future net cash flows. No ceiling write-downs were recorded in 2007, 2006, or 2005.
Pipeline Facilities
Phase I of the pipeline was completed during 1999. Phase II of the pipeline was completed on March 8, 2001. Both phases of the pipeline were placed into service upon completion of Phase II. The pipeline is being depreciated over its estimated useful life of 30 years beginning at the time it was placed in service.
Other Property and Equipment and Long - Lived Assets
Other property and equipment are carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from three to seven years. Long-lived assets (other than oil and gas properties) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
When evidence indicates that operations will not produce sufficient cash flows to cover the carrying amount of the related asset, a permanent impairment is recorded to adjust the asset to fair value. At December 31, 2007, management believes that carrying amounts of all of the Company’s long-lived assets will be fully recovered over the course of the Company’s normal future operations.
Stock-Based Compensation
The Company recorded $100,877 in 2007, $128,197 in 2006 and $84,030 in compensation expense in 2005 upon the Company’s adoption of SFAS 123 (R) in 2005.
Accounts Receivable
Senior management reviews accounts receivable on a monthly basis to determine if any receivables will potentially be uncollectible. Based on the information available to us, the Company believes no allowance for doubtful accounts as of December 31, 2007 and 2006 is necessary. However, actual write-offs may occur.
Income Taxes
The Company accounts for income taxes using the “asset and liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets arise primarily from net operating loss carry-forwards. Management evaluates the likelihood of realization for such assets at year-end providing a valuation allowance for any such amounts not likely to be recovered in future periods. The Company currently has a net operating loss carry forward of 21,100,000.
Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. At times, such cash in banks is in excess of the FDIC insurance limit.
The Company’s primary business activities include oil and gas sales to several customers in the states of Kansas and Tennessee. The related trade receivables subject the Company to a concentration of credit risk within the oil and gas industry.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company is presently dependent upon a small number of customers for the sale of gas from the Swan Creek Field, principally Eastman Chemical Company and other industrial customers in the Kingsport area with which the Company may enter into gas sales contracts.
The Company has entered into contracts to supply two manufacturers with natural gas from the Swan Creek Field (Tennessee) through the Company’s pipeline. These customers are the Company’s primary customers for natural gas sales. Additionally, the Company sells a majority of its crude oil primarily to two customers, one each in Tennessee and Kansas. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it could have a significant adverse effect on the Company’s projected results of operations.
In 2007, the Company received 91.4 percent of its revenues from Customer A; 4.9 percent of its revenues from Customer B; and 3.7 percent of its revenues from Customer C.
In 2006, the Company received 85.7 percent of its revenues from Customer A; 10.1 percent of its revenues from Customer B.
In 2005, the Company received 74.6 percent of its revenues from Customer A; 18.6 percent of its revenues from Customer B.
In each of the years 2005 through 2007, the identity of the customers indicated above as either A, B or C was the same from year to year, although the percentage of revenues varied from year to year for those customers.
In accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share” (“SFAS 128”), basic income per share is based on 59,117,176, 58,851,883 and 52,019,051 weighted average shares outstanding for the years ended December 31, 2007, December 31, 2006 and December 31, 2005 respectively. Diluted earnings per common share are computed by dividing income available to common shareholders by the weighted average number of shares of common stock outstanding during the period increased to include the number of additional shares of common stock that would have been outstanding if the dilutive potential shares of common stock had been issued. The dilutive effect of outstanding options and warrants is reflected in diluted earnings per share.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The number of dilutive shares outstanding is 1,710,048 for 2007, 1,512,914 for 2006 and 640,000 for 2005. These are related to options and warrants.
Fair Values of Financial Instruments
Fair values of cash and cash equivalents, investments and short-term debt approximate their carrying values due to the short period of time to maturity. Fair values of long-term debt are based on quoted market prices or pricing models using current market rates, which approximate carrying values.
(2.) Recent Accounting Pronouncements
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 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. The adoption of FIN 48 had no impact on our results of operations or financial position. The Company currently has open tax return periods beginning with December 31, 2004 through December 31, 2007.
In September 2006, the Securities and Exchange Commission staff published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The Company adopted SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. It defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurement
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. It clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company continues to evaluate the impact the adoption of this statement could have on its financial condition, results of operations and cash flows.
In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities - as amended (“SFAS 159”). SFAS 159 permits entities to elect to report eligible financial instruments at fair value subject to conditions stated in the pronouncement including adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial reporting by mitigating volatility in earnings related to current reporting requirements. The Company is considering the applicability of SFAS 159 and will determine if adoption is appropriate. The effective date for SFAS 159 is for fiscal years beginning after November 15, 2007.
In October, 2005 the Company accepted an exchange from 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. to fund the Company’s cash exchange to holders of its Series A, B and C Preferred Stock.
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 continuing to produce 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, 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, all well-drilling obligations of the Company under both the Eight Well and Twelve Well Programs with former preferred stockholders as participants have been satisfied.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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. 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.
On September 17, 2007, the Company entered into a drilling program with Hoactzin for ten wells consisting of approximately three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas Properties (the “Program”). Under the terms of the Program, Hoactzin was to pay the Company $400,000 for each well in the Program completed as a producing well and $250,00 per drilled well that was non-productive. The terms of Program also provide that Hoactzin will receive all the working interest in the ten wells in the Program, but will pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses. This is referred to as a management fee but as defined is in the nature of a net profits interest. The fee paid to the Company by Hoactzin will increase to 85% of working interest revenues when net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”). The Company will account for funds received for interests in the Program as an offset to oil and gas properties.
As of the date of this Report, the Company has drilled all ten wells in the Program. Of the ten wells drilled, nine were completed as oil producers and are currently producing approximately 84 barrels per day in total. Hoactzin paid a total of $3,850,000 for its interest in the Program resulting in the Payout Point being determined as $5,215,595. The amount paid by Hoactzin for its interest in the Program wells exceeded the Company’s actual drilling costs of approximately $2.8 million for the ten wells by more than $1 million.
Although production level of the Program wells will decline with time in accordance with expected decline curves for these types of well, based on the drilling results of the Program wells and the current price of oil, the Program wells are expected to reach the Payout Point in approximately four years solely from the oil revenues from the wells. However, under the terms of its agreement with Hoactzin reaching the Payout Point has been accelerated by Hoactzin agreeing to apply 75% of the net proceeds it receives from the methane extraction project being developed by the Company’s wholly-owned subsidiary, Manufactured Methane Corporation, at the Carter Valley, Tennessee landfill to the Payout Point. (The methane extraction project is discussed in greater detail below.) Those methane project proceeds when applied will result in the Payout Point being achieved sooner than the estimated four year period based solely upon revenues from the Program wells.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
On December 18, 2007, the Company entered into a Management Agreement with Hoactzin. On that same date, the Company also entered into an agreement with Charles Patrick McInturff employing him as a Vice-President of the Company. Pursuant to the Management Agreement with Hoactzin, Mr. McInturff’s duties while he is employed as Vice-President of the Company will include the management on behalf of Hoactzin of its working interests in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As consideration for the Company entering into the Management Agreement, Hoactzin has agreed that it will be responsible to reimburse the Company for the payment of one-half of Mr. McInturff’s salary, as well as certain other benefits he receives during his employment by the Company. In further consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin has granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or work-over activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement. The term of the Management Agreement is the earlier of the date Hoactzin sells its interests in its managed properties or 5 years.
The following table sets forth information concerning the Company’s oil and gas properties:
December 31,
Oil and gas properties, at cost
18,856,487
$ 18,745,834
Unevaluated properties
3,110,768
1,880,811
Accumulation depreciation,
depletion and amortization
(8,757,654)
(7,923,016)
Oil and gas properties, net
13,209,601
$ 12,703,629
During the years ended December 31, 2007, 2006 and 2005 the Company recorded depletion expense of $834,638, $1,144,711 and $902,131 in 2005.
In 1996, the Company began construction of a 65-mile gas pipeline (1) connecting the Swan Creek development project to a gas purchaser and (2) enabling the Company to develop gas transportation business opportunities in the future. Phase I, a 30-mile portion of the pipeline, was completed in 1998. Phase II of the pipeline, the remaining 35 miles, was completed in March 2001. The estimated useful life of the pipeline for depreciation purposes is 30 years. The Company recorded $544,000, $544,000 and $536,000, in depreciation expense related to the pipeline for the years ended December 31, 2007, 2006 and 2005, respectively.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
In January 1997, the Company entered into an agreement with the Tennessee Valley Authority (“TVA”) whereby the TVA allows the Company to bury the pipeline within the TVA’s transmission line rights-of-way. In return for this right, the Company paid $35,000 and agreed to annual payments of approximately $6,200 for 20 years.
This agreement expires in 2017 at which time the parties may renew the agreement for another 20-year term in consideration of similar inflation-adjusted payment terms.
Other property and equipment consisted of the following:
December 31
Depreciable Life
Machinery and equipment
5-7 yrs
$ 830,734
$ 771,767
Vehicles
2-5 yrs
487,176
521,824
Other
5 yrs
63,734
63,734
Total
1,381,644
1,357,325
Less accumulated depreciation
(1,125,586)
(1,089,612)
Other property and equipment - net
$ 256,058
$ 267,713
The Company uses the straight-line method of depreciation ranging from two years to seven years, depending on the asset life.
Long-term debt to unrelated entities consisted of the following:
December 31,
Note payable to a financial institution, with interest payment only until maturity.
(See Notes 15 & 16)
$4,200,000
$ 2,600,000
Installment notes bearing interest at the rate of 5.5% to 8.25% per annum collateralized by vehicles with monthly payments including interest of approximately $10,000 due through 2010.
173,660
195,801
Total long-term debt
4,373,660
2,795,801
Less current maturities
(57,887)
(65,267)
Long-term debt, less current
maturities
4,315,773
$ 2,730,534
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
8.
Commitments and Contingencies
The Company is a party to lawsuits in the ordinary course of its business. The Company does not believe that it is probable that the outcome of any individual action will have a material adverse effect, or that it is likely that adverse outcomes of individually insignificant actions will be significant enough, in number or magnitude, to have in the aggregate a material adverse effect on its financial statements.
In the ordinary course of business the Company has entered into office leases which have remaining term of 6 months. Approximate future minimum lease payments to be made under non-cancelable operating leases in 2008 are $31,673.
Office rent expense for each of the three years ended December 31, 2007, 2006 and 2005 was approximately $63,346, $63,346, and $ 83,332 respectively.
9.
Cumulative Convertible Redeemable
On August 22, 2005 all holders of the Company's Series B and C Cumulative Convertible Preferred Stock (the "Series B and Series C shares"), having a total aggregate value of $5,113,045 consisting of face value, dividends, and interest exchanged all rights under their Series B and C shares for cash or for the Company's common stock. As a result of the exchange, as of August 22, 2005 the Company no longer had any holders of Series B or C preferred stock and no further obligations under any Series B or C shares. Holders of approximately 53.2% of the face value of outstanding Series B and C shares exchanged their preferred shares having an aggregate value of $2,721,140 for cash payments totaling $1,814,184. The Company obtained the funds for this exchange primarily from proceeds of a loan of $1,814,000 from Dolphin. The loan from Dolphin was evidenced by a secured promissory note dated August 22, 2005 bearing 12% interest per annum payable interest only monthly until the principal amount of the note was to become due on December 31, 2005. A second option offered to the Series B and C holders 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. All of the holders, including Dolphin, of the remaining aggregate value of $2,391,905 or 46.8% of the Series B and C shares selected this option. As a result, a total of 9,567,620 shares of the Company's common stock were issued to those holders. 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.
In total, the Company recorded a gain during 2005 from the exchange of Series A, B and C shares for cash and stock of $655,746, the difference between the carrying amount and the cash settlement amount and the stock issued.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company follows the requirements of SFAS 143. Among other things, SFAS 143 requires entities to record a liability and corresponding increase in long-lived assets for the present value of material obligations associated with the retirement of tangible long-lived assets. Over the passage of time, accretion of the liability is recognized as an operating expense and the capitalized cost is depleted over the estimated useful life of the related asset. Additionally, SFAS 143 required that upon initial application of these standards, the Company must recognize a cumulative effect of a change in accounting principle corresponding to the accumulated accretion and depletion expense that would have been recognized had this standard been applied at the time the long-lived assets were acquired or constructed. The Company’s asset retirement obligations relate primarily to the plugging, dismantling and removal of wells drilled to date. The Company’s calculation of Asset Retirement Obligation used a credit-adjusted risk free rate of 12%, an estimated useful life of wells ranging from 30-40 years, estimated plugging and abandonment cost range from $5,000 per well to $10,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions.
On March 4, 2005 the Company sold its Kansas gas wells, and consequently the asset and the corresponding liability relating to asset retirement obligations on these wells were extinguished. The asset account was credited for $60,998 and the liability was removed in the amount of $133,397, creating a gain on the extinguishment of future obligations in the amount of $72,399, which was credited to interest expense.
The following is a roll-forward of activity impacting the asset retirement obligation for the year ended December 31, 2007:
Balance, December 31, 2005
$ 566,968
Accretion expense
42,340
Liabilities Settled
(97,293)
Balance, December 31, 2006
$ 512,015
Accretion expense
70,929
Liabilities Settled
(51,843)
Balance, December 31, 2007
$ 531,101
In October 2000, the Company approved a Stock Incentive Plan. The Plan is effective for a ten-year period commencing on October 25, 2000 and ending on October 24, 2010. The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to participants under the plan shall not exceed 3,500,000. Options are not transferable, are exercisable for 3 months after voluntary
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
resignation from the Company, and terminate immediately upon involuntary termination from the Company. The purchase price of shares subject to this plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the fair market value of such shares on the date of grant. Furthermore, a participant in the Plan may not, immediately prior to the grant of an Incentive Stock Option hereunder, own stock in the Company representing more than ten percent of the total voting power of all classes of stock of the Company unless the per share option price specified by the Board for the Incentive Stock Options granted such a participant is at least 110% of the fair market value of the Company’s stock on the date of grant and such option, by its terms, is not exercisable after the expiration of 5 years from the date such stock option is granted.
Stock option activity in 2007, 2006 and 2005 is summarized below:
The following table summarizes information about stock options outstanding and exercisable at December 31, 2006:
Options Outstanding
Options Exercisable
Weighted Average
Exercise Price
Shares
Weighted Average
Remaining
Contractual
Life (years)
Shares
$ 0.27
2,251,000
2.33
1,357,000
$ 0.58
110,000
3.05
110,000
$ 0.81
80,000
3.93
80,000
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The weighted average fair value per share of options granted during 2006 and 2005 range from $0.15 to $0.32, calculated using the Black-Scholes Option-Pricing model. No options were granted in 2007.
Compensation expense of $84,030 related to stock options was recognized in 2005 and $128,197 in 2006 and 100,877 in 2007.
The fair value of stock options used to compute pro forma net loss and loss per share disclosures is the estimated present value at grant date using the Black-Scholes option-pricing model with the following weighted average assumptions for 2006 and 2005: expected volatility of 60% for 2006, and 2005; a risk free interest rate of 3.67% in 2006 and 2005; and an expected option life of 2.5 years for 2006 and 2005.
The Company has taxable income for the periods ending December 31, 2007, December 31, 2006 and December 31, 2005.
A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows:
December 31,
Statutory rate
34%
34%
34%
Tax (benefit)/expense
at statutory rate
1,193,000
$ 728,000
$ 370,000
State income
tax (benefit)/expense
140,000
85,000
43,000
Other
3,000
3,000
3,000
Non-deductible interest
-
Increase/(decreases)in deferred tax asset valuation allowance
(3,436,000)
(816,000)
(416,000)
Total income tax provision (benefit)
(2,100,000)
-
-
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company’s deferred tax assets and liabilities are as follows:
December 31
Deferred tax assets:
Net operating loss carryforward
$7,314,000
$ 8,700,000
$ 9,616,000
Capital loss carry forward
263,000
263,000
263,000
Total deferred tax assets
7,577,000
8,963,000
9,879,000
Deferred tax liability:
Basis difference in pipeline
250,000
300,000
400,000
Total deferred liability
250,000
300,000
400,000
Total net deferred taxes
7,327,000
8,663,000
9,479,000
Valuation allowance
(5,227,000)
(8,663,000)
(9,479,000)
Net deferred tax asset
$2,100,000
-
-
As of December 31, 2007, Management, using the “more likely than not” criteria for recognition, elected to recognize a deferred tax asset of $2.1 million. The recognition of the deferred tax asset in 2007 relates to net operating loss carryforwards and will provide a better matching of income tax expense with taxable income in future periods. The current provision reflects the recognition of $1,336,000 current income tax benefit (fully offset by the current provision related to 2007 taxable income) and $2,100,000 in benefit relating to future periods.
No income tax expense was recognized for the years ended December 31, 2006 or December 31, 2005 because deferred tax benefits, derived from the Company’s prior net operating losses, were previously fully reserved and were being offset against tax liabilities that would otherwise arise from the results of current operations. Management continuously estimates the realization of the Company’s deferred tax assets based on its anticipation of the likely timing and adequacy of future net income, after taking into consideration the increased uncertainty attributed to a lengthening horizon before the projected realization of future deferred assets.
As of December 31, 2007, the Company had net operating loss carry-forwards of approximately $21,100,000 which will expire between 2011 and 2023 if not utilized.
The Company paid approximately $262,268, $126,250, and $524,000, for interest in 2007, 2006 and 2005, respectively. No interest was capitalized in 2007, 2006 or 2005. No income taxes were paid in 2007, 2006, or 2005.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
On May 10, 2004 the Court entered its final order approving the fairness of the settlement to the class, dismissing the action pursuant to a Settlement Stipulation, and fully releasing the claims of the class members in Paul Miller v. M. E. Ratliff and Tengasco, Inc., No. 3:02-CV-644 in the United States District Court for the Eastern District of Tennessee, Knoxville, Tennessee. This action sought certification of a class action to recover on behalf of a class of all persons who purchased shares of the Company’s common stock between August 1, 2001 and April 23, 2002, unspecified damages allegedly caused by violations of the federal securities laws. In January, 2004 all parties reached a settlement subject to court approval. The Court entered its order approving the settlement on May 10, 2004. Under the settlement, the Company paid into a settlement fund the amount of $37,500 to include all costs of administration, contributed 150,000 shares of stock of Miller Petroleum, Inc. owned by the Company and issued 300,000 warrants to purchase a share of the Company’s common stock for a period of three years from date of issue at $1 per share subject to adjustments. The Rights Offering adjusted this price to $0.45 per share. These Warrants expire on September 12, 2008. The Miller Petroleum, Inc. investment had a net carrying value of $60,000 and a cumulative other comprehensive loss of $90,000, which was reversed from cumulative other comprehensive loss and recognized as a realized loss during the third quarter of 2004.
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 an initial 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. The facility has standard loan covenants such as current ratios, interest coverage ratios etc, with which the Company is in compliance.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
$1.393 million of the $2.6 million loan proceeds were used by the Company on June 29, 2006 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 12-well Kansas drilling program for Hoactzin. The Company incurred loan closing costs consisting of legal fees, mortgage taxes, commissions and bank fees totaling $285,224. This amount will be amortized over the term of the note and its successor (See Note 16).
On April 19, 2007 the Company borrowed an additional sum of $700,000 from Citibank, N.A. under its existing revolving credit facility dated June 29, 2006. The additional borrowing resulted from an increase in the Company’s borrowing base under the Citibank credit facility from $2.6 million to $3.3 million based upon Citibank’s periodic review of the Company’s borrowing base. With the additional borrowing, the Company has borrowed the full amount of its $3.3 million borrowing base under the revolving Citibank credit facility. Repayment of this additional sum is subject to the terms and conditions of the Citibank credit facility. The additional amount borrowed will be used for further development of the Company’s producing properties.
On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by the Company.
Under the facility as assigned to Sovereign, 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 $20 million or the Company’s borrowing base in effect from time to time. The Company’s initial borrowing base with Sovereign was set at $7.0 million, an increase from its borrowing base of $3.3 million with Citibank prior to the assignment.
The Company’s initial borrowing on December 17, 2007 under its new facility with Sovereign was approximately $4.2 million which will bear interest at a floating rate equal to prime as published in the Wall Street Journal plus 0.25% resulting in a current interest rate of approximately 7.5%. Interest only is payable during the term of the loan and the principal balance of the loan is due December 31, 2010. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane Project assets.
The Company used a portion of the $4.2 million borrowed from Sovereign to pay off the funds it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign was used to pay bank fees and attorney fees relating to the assignment in the amount of approximately $75,000 and the balance of approximately $825,000 was used to pay a portion of the purchase price for equipment to be utilized in the Methane Project currently under construction in Carter Valley, Tennessee by MCC, the Company’s wholly-owned subsidiary.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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 was thereafter assigned to the Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) and provides that MMC will purchase all the naturally produced gas stream presently being collected and flared at the municipal solid waste landfill in Carter Valley 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 (the “Methane Project”).
MCC has placed equipment orders for its first stage of process equipment (cleanup and carbon dioxide removal) and the second stage of process equipment (nitrogen rejection) for the Methane Project. It is anticipated that the total costs for the Project including pipeline construction, will be approximately $4.1 million including costs for compression and interstage controls. The costs of the Methane Project to date have been funded primarily by (a) the money received by the Company from Hoactzin to purchase its interest in the Ten Well Program which exceeded the Company’s actual costs of drilling the wells in that Program by more than $1 million (b) cash flow from the Company’s operations in the amount of approximately $1 million and (c) $825,000 of the funds the Company borrowed from its credit facility with Sovereign Bank. The Company anticipates that most of the remaining balance of the Methane Project costs will be paid from the Company’s cash flow.
The Company anticipates that the equipment ordered by MMC will be manufactured and delivered to allow operations to begin in mid-2008 after equipment installation, testing, and startup procedures are begun. Commercial deliveries of gas will begin when the equipment is installed and tested and the pipeline is constructed. Upon commencement of operations, the methane gas produced by the project facilities will be mixed in the Company’s pipeline and delivered and sold to Eastman Chemical Company (“Eastman”) under the terms of the Company’s existing natural gas purchase and sale agreement. 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 substantially increase the current volumes of natural gas being delivered to Eastman by the Company from its Swan Creek field. At an assumed sales price of gas of $7 per MMBtu, near the average natural gas price received by the Company in 2007, the anticipated net revenues to the Company would be approximately $800,000 per year from the Methane Project based on anticipated volumes and expenses. The gas supply from this project is projected to grow over the years as the underlying operating
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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.
As part of the Methane Project agreement, the Company agreed to install a new force-main water drainage line for Allied Waste Industries, an affiliate of BFI, the landfill owner, in the same two-mile pipeline trench as the gas pipeline needed for the project, reducing overall costs and avoiding environmental effects to private landowners resulting from multiple installations of pipeline. Allied Waste will pay the additional costs for including the water line. Construction of the gas pipeline needed to connect the facility with the Company’s existing natural gas pipeline began in January 2008. As a certificated utility, the Company’s pipeline subsidiary, TPC, requires no additional permits for the gas pipeline construction. The Company currently anticipates that pipeline construction will be concluded approximately the same time as equipment deliveries and installations occur or in the May to June 2008 time period, subject to weather delays during wintertime construction.
On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program, pursuant to a separate agreement with the Company was conveyed a 75% net profits interest in the Methane Project. When the Methane Project comes online, the revenues from the Project received by Hoactzin will be applied towards the determination of the Payout Point (as defined above) for the Ten Well Program. When the Payout Point is reached from either the revenues from the wells drilled in the Program or the Methane Project or a combination thereof, Hoactzin’s net profits interest in the Methane Project will decrease to a 7.5% net profits interest. The Company believes that the application of revenues from the methane project to reach the Payout Point will rapidly accelerate reaching the Payout Point. Those excess funds provided by Hoactzin were used to pay for approximately $1,000,000 of equipment required for the Methane Project, or about 25% of the Project’s capital costs. The availability of the funds provided by Hoactzin eliminated the need for the Company to borrow those funds, to have to pay interest to any lending institution making such loans or to dedicate Company revenues or revenues from the Methane Project to pay such debt service. Accordingly, the grant of a 7.5% interest in the Methane Project to Hoactzin was negotiated by the Company as a favorable provision to the Company in the overall transaction.
As security required by Tennessee oil and gas regulations, the Company placed $120,500 in a Certificate of Deposit to cover future asset retirement obligations for the Company’s Tennessee wells.
The following table sets forth for the fiscal periods indicated, selected consolidated financial data.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Fiscal Year Ended 2007
First Quarter
Second Quarter
Third Quarter(a)
Fourth Quarter(a)
Revenues
$1,772,400
$2,220,439
$2,375,229
$3,000,556
Net loss/income
($209,165)
$ 330,756
$1,580,662
$1,808,069
Net loss/income attributable to common stockholders
($209,165)
$330,756
$1,580,662
$1,808,069
Income/loss per common share
$ 0.00
$ .01
$ 0.03
$ 0.03
Fiscal Year Ended 2006
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Revenues
$ 2,098,969
$ 2,354,736
$ 2,251,274
$ 2,296,702
Net loss/income
316,347
720,769
519,094
585,154
Net loss/income attributable to common stockholders
$ 316,347
$ 720,769
$ 519,094
$ 585,154
Income/loss per common share
$ 0.01
$ 0.01
$
0.01
$
0.01
(a)
The company recorded 1.1 million in deferred tax asset in the third quarter of 2007 and 1.0 million in the fourth quarter of 2007.
20. Supplemental Oil and Gas Information (unaudited)
Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserve quantities, as well as future production and discounted cash flows before income taxes, were determined by Ryder Scott Company, L.P. as of December 31, 2005, The reserves were estimated by LaRoche Petroleum Consultants Ltd. in 2006 and 2007.
Oil and Gas Related Costs
The following table sets forth information concerning costs related to the Company’s oil and gas property acquisition, exploration and development activities in the United States during the years ended:
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Property acquisitions
Proved
200,000
Unproved
-
Less -proceeds from
Sales of properties
-
-
$ (2,651,770)
Development Cost
4,990,611
4,172,462
402,876
5,190,611
$ 4,172,462
$ (2,248,894)
Results of Operations from Oil and Gas Producing Activities
The following table sets forth the Company’s results of operations from oil and gas producing activities for the years ended:December 31,
Revenues
9,300,144
$ 8,896,036
$ 7,076,790
Production costs and taxes
(4,160,488)
(3,145,244)
(2,956,307)
Depreciation, depletion and amortization
(834,638)
(1,144,711)
(902,132)
Income from oil and gas producing activities
4,305,018
$ 4,606,081
$ 3,218,351
In the presentation above, no deduction has been made for indirect costs such as corporate overhead or interest expense. No income taxes are reflected above due to the Company’s operating tax loss carry-forwards.
Oil and Gas Reserves
The following table sets forth the Company’s net proved oil and gas reserves at December 31, 2007, 2006 and 2005 and the changes in net proved oil and gas reserves for the years then ended. Proved reserves represent the quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future years from known reservoirs under existing economic and operating conditions. Reserves are measured in barrels (bbls) in the case of oil, and units of one thousand cubic feet (Mcf) in the case of gas.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following two tables:
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using current sales prices, along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The average prices used at December 31, 2007, 2006, and 2005 were $85.44, $56.50, and $55.81, per barrel of oil and $7.21, $8.33 and $11.31 per MCF of gas, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
Operating costs and production taxes are estimated based on current costs with respect to producing properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable net operating loss carry-forwards, for both regular and alternative minimum tax. For the years ended December 31, 2007, 2006 and 2005 the Company’s available net operating loss carry forwards offset all tax effects applicable to the discounted future net cash flows.
The future net revenue information assumes no escalation of costs or prices, except for gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.
ITEM 6.
SELECTED FINANCIAL DATA
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,
Income Statement Data:
Oil and Gas Revenues
$9,300,144
$8,896,036
$7,067,790
$6,013,374
$6,040,872
Production Cost and Taxes
$4,322,833
$3,287,233
$3,046,460
$3,364,429
$3,412,201
General and
Administrative
$1,417,001
$1,293,109
$1,322,616
$1,777,183
$1,486,280
Interest Expense
$ 333,198
$ 168,590
$ 472,655
$1,367,180
$1,120,738
Net Income/Loss
$3,510,322
$2,141,364
$1,088,028
$(1,994,025)
$(3,197,662)
Net Income/Loss Attributable to Common Stockholders
$3,510,322
$2,141,364
$1,088,028
$(1,994,025)
$(3,451,580)
Net Income/Loss Attributable to Common Stockholder Per Share
$ 0.06
$ 0.04
$ 0.02
$
(0.05)
$
(0.29)
Year Ended December 31,5,6
Balance Sheet Data:
Working Capital Surplus
(Deficit)
$ 2,473,4767
$872,507
$(1,334,744)
$(6,753,721)
$(10,822,717)
Oil and Gas Properties, Net
$13,209,601
$12,703,629
$ 9,675,977
$ 12,826,903
$12,989,443
Pipeline Facilities, Net
$12,916,667
$13,460,667
$13,994,453
$ 14,602,639
$15,139,789
Total Assets
$34,281,549
$28,454,338
$25,908,616
$ 28,209,749
$30,604,240
Long-Term Debt
$ 4,315,773
$ 2,730,534
$ 117,912
$ 1,940,890
$ 6,256,818
Redeemable
Preferred Stock
$ -0-
$ -0-
$ -0-
$ -0-
$ -0-
Stockholders Equity
$28,102,871
$24,420,205
$ 21,961,454
$18,349,687
$11,251,871
ITEM 7.
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
The Company incurred a net income to holders of common stock of $3,510,322 or $0.06 per share in 2007 compared to a net income of $2,141,364 or $0.04 per share in 2006 and compared to a net income of $1,088,028 or $0.02 per share in 2005. The Company recognized a tax benefit for net operating loss carry forwards in the amount of $2,100,000 in 2007.
The Company realized revenues of $9,368,624 in 2007 compared to $9,001,681 in 2006 and compared to $7,172,876 in 2005. Revenues increased $366,943 from 2006 due primarily to an increase in oil prices in Kansas; prices averaged $66.42 in 2007 and 60.84 in 2006. Gross oil production in 2007 was just slightly less than 2006 resulting from the loss of production in January 2007 due to the electricity outage during an ice storm. As a result of that storm, many counties in Kansas, including some counties where the Company has wells, lost power for the entire month of January. Producing wells in those counties were unable to produce without electricity to run the well pumps during the power outage. Consequently in January 2007 the Company saw production and revenue decline from monthly levels in late 2006. None of the Company’s producing wells were physically damaged by the ice storm or by non
_________________________
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.
The Company’s working capital surplus of 2,473.476 was attributable to high commodity prices as well as an increase in the borrowing base by $900,000 on December 17, 2007 and the funding of the Ten Well Program. The Company has expended approximately $1.5 million of these funds subsequent to year-end on the Methane Project and completing the Ten Well Program.
-
production during the absence of power, but the storm did substantially adversely impact production levels and sales in the first two months of 2007 while at the same time causing an increase in expenses. Eventually new poles and lines were rebuilt on a locally massive scale and electrical power was restored, and the Company experienced a rebound of production commencing in March 2007.
In 2007 the Company produced 178,311 barrels of oil in Kansas compared to 179,555 in 2006, a decrease of 1,244 barrels for the year. Additionally, the wells in the Eight Well Program (former Series “A”) reached the reversionary “flip point” in April 2007. This is the point at which the Company started receiving 85% of the participant’s interest plus our original interest of (19.3%) for an approximate total net interest to the Company equal to an 88% interest. In 2007 those wells produced 22,195 gross barrels of oil; the wells in the Twelve Well Program (former Series “B”) now converted to a six well program produced 15,864 gross barrels; wells polymered produced 19,502 barrels; and, the two new wells drilled produced 2,566 gross barrels in 2007. During 2007 the Company drilled 9 of the 10 wells in the Ten Well Program and produced 3,649 barrels from the 5 wells that were completed by year-end. The other three wells that were drilled in 2007 were then completed in 2008. In March 2008, the tenth and final well in the Ten Well Program was both drilled and completed as a producer. As of the date of this report, nine of ten wells drilled in the Ten Well Program have been completed as producers and are producing approximately 106 barrels per day. During the first half of 2008 the Company expects the reversionary flip point for the Twelve Well Program (former Series “B”) now converted to a six well program, to be achieved.
Gas prices received for sales of gas from the Swan Creek Field averaged $6.86 per Mcf in 2007, $7.27 per Mcf in 2006 and $8.74 per Mcf in 2005. Oil prices received for sales of oil from the Swan Creek field averaged $64.81 per barrel in 2007, and $60.39 per barrel in 2006, and. $53.90 per barrel in 2005.
Production costs and taxes in 2007 increased to $4,322,833 from $3,287,233 in 2006 and $3,046,460 in 2005. The difference is due to increased work-overs to increase production, increased taxes, and overall cost increases of supplies in the industry.
Depletion, depreciation, and amortization for 2007 was $1,631,468, a decrease from $1,911,416 in 2006 due to production volumes added to future reserves from drilling activities. Depletion, depreciation, and amortization increased to $1,911,416 in 2006 from $1,605,043 in 2005. The increase in 2006 was 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 Company’s general and administrative costs of $1,417,001 in 2007 remained generally consistent with 2006 levels of $1,293,109 and 2005 levels of $1,322,616. The 2007, 2006 and 2005 costs included non-cash charges related to stock options of $116,476, $159,160 and $103,400 respectively.
The increase in interest expense in 2007 relates to the borrowing base increase of the Citibank credit facility in 2007. Interest expense for 2006 decreased significantly over 2005 levels. This was due to the conversion of the Company’s preferred stock, which was subject to mandatory redemption, into either interest in a drilling program, common stock or cash payoffs. As of December 31, 2006, the Company’s only debt financing were vehicle loans totaling $195,801 and the CitiBank loan of $2,600,000.
The Company’s public relations costs remained stable at $21,605 for 2007, compared to $26,037 for 2006 and $30,020 for 2005 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 2007 were $232,197 compared to $173,932 in 2006. This was due to the Company commencing its review of its internal controls over its financial reporting in accordance with Item 308(T) of Regulation S-K. Professional fees in 2006 decreased from 2005 levels as the Company’s litigation was settled.
The Company recorded a deferred tax asset of $2,100,000 in 2007 relating to the Company’s net operating loss carry forwards. The Company recorded a gain on disposal of preferred stock of $655,746 in 2005.
Liquidity and Capital Resources
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 were 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 interest of approximately 8.2%. Interest only was 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.
The Company used $1.393 million of the proceeds of the $2.6 million loan from Citibank to exercise the Company’s option to repurchase from Hoactzin Partners, L.P. (“Hoactzin”), the Company’s obligation to drill for Hoactzin the final six wells of the Company’s Twelve Well Program. Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin. He is also the sole shareholder and controlling person of Dolphin Management, Inc., the general partner of Dolphin Offshore Partners, L.P., which is the Company’s largest shareholder. A detailed description of the Twelve Well Program is set forth In “Item 1 - Business” under the subheading “Kansas Drilling Programs”.
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. 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 was 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 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) as well as the Company’s earlier Eight Well Program (offered to the former Series A preferred stockholders).
Under the terms of the Eight Well Program and Twelve (now Six) Well program, 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 was reached in April 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 during the first half of 2008. It is anticipated, based upon current volumes and prices that this will result in an increase in revenues to the Company of approximately $50,000 per month.
On April 19, 2007 the Company borrowed an additional $700,000 from Citibank under the existing Citibank revolving credit facility. The additional borrowing resulted from Citibank’s increase in the Company’s borrowing base under the credit facility from $2.6 million to $3.3 million as a result of Citibank’s periodic borrowing base review conducted under the terms of credit facility. With the additional borrowing, the Company had borrowed the full amount of the $3.3 million borrowing base which was available to it under the Citibank revolving credit facility. Repayment of this additional sum was subject to the terms and conditions of the Citibank credit facility. The additional amount borrowed was used for additional development of the Company’s producing properties.
On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by the Company.
Under the facility as assigned to Sovereign, 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 $20 million or the Company’s borrowing base in effect from time to time. The Company’s initial borrowing base with Sovereign was set at $7.0 million, an increase from its borrowing base of $3.3 million with Citibank prior to the assignment.
The Company’s initial borrowing on December 17, 2007 under its new facility with Sovereign was approximately $4.2 million which will bear interest at a floating rate equal to prime as published in the Wall Street Journal plus 0.25% resulting in a current interest rate of
approximately 7.5%. Interest only is payable during the term of the loan and the principal balance of the loan is due December 31, 2010. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane Project assets.
The Company used a portion of the $4.2 million borrowed from Sovereign to pay off the funds it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign was used to pay bank fees and attorney fees relating to the assignment in the amount of approximately $75,000 and the balance of approximately $825,000 was used to pay a portion of the purchase price for equipment to be utilized in the Methane Project currently under construction in Church Hill, Tennessee by MMC, the Company’s wholly-owned subsidiary. See, “Item 1 - Business” under the subheading “The Methane Project”.
Net cash provided by operating activities for 2007 was $3,446,677 compared to net cash provided by operating activities of $4,353,966 in 2006. The Company’s net income in 2007 increased to $3,510,322 from $2,141,364 in 2006. The impact on cash provided by operating activities was due to the net income for 2007 and was increased by non-cash depletion, depreciation, and amortization of $1,631,468 and by non-cash compensation and services paid by insurance of equity instruments of $116,476. Cash flow provided in working capital items in 2007 was $211,742 compared to cash provided by working capital items of $122,152 in 2006. The Company’s net income for 2007 included a non-cash deferred tax asset for net operating loss carry forwards of $2,100,000.
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 $1,911,416 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 used in investing activities amounted to $3,145,764 for 2007 compared to net cash used in investment activities in the amount of $4,413,185 for 2006. The decrease in net cash used in investing activities during 2006 was primarily attributable to an increase in oil and gas properties of $5,190,611 offset by drilling program funds received of $3,850,000 and an increase in additions to methane project of $1,649,710.
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 financing activities increased to $1,556,261 in 2007 from cash provided by financing activities of $167,915 in 2006. In 2007 the primary sources of financing included proceeds from borrowings of $1,687,236 compared to $2,732,145 in 2006. The primary use of cash in financing activities in 2006 was to repay the drilling program liability of $2,324,400.
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.
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.
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 2007, 2006 or 2005.
Oil and Gas Reserves/Depletion Depreciation
And Amortization of Oil and Gas Properties
The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated 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, 2007 were determined by LaRoche Petroleum Consultants, Ltd. Projecting the effects of commodity prices on production, and timing of development expenditures includes many factors beyond the Company’s control. The future estimates of net cash flows from the Company’s proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates.
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 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 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, the Company adopted FIN 48 on January 1, 2007. The Company does not expect the interpretation will have an impact on its results of operations or financial position.
In September 2006, the Securities and Exchange Commission staff published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The Company adopted SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. It defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurement. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. It clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company continues to evaluate the impact the adoption of this statement could have on its financial condition, results of operations and cash flows.
In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities - As amended” (“SFAS 159”). SFAS 159 permits entities to elect to report eligible financial instruments at fair value subject to conditions stated in the pronouncement including adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial reporting by mitigating volatility in earnings related to current reporting requirements. The Company is considering the applicability of SFAS 159 and will determine if
adoption is appropriate. The effective date for SFAS 159 is for fiscal years beginning after November 15, 2007.
CONTRACTUAL OBLIGATIONS
The following table summarizes the Company’s contractual obligations at December 31, 2007:
Payments Due By Period
Contractual Obligations
Total
Less than
1year
1-3
years
3-5
years
More than
5 years
Long-Term Debt Obligations8
$4,373,660
57,887
$4,315,773
$-0-
$-0-
Capital Lease Obligations
$-0-
$-0-
$-0-
$-0-
$-0-
Operating Lease Obligations9
$31,673
$31,673
$-0-
$-0-
$-0-
Purchase Obligations
$-0-
$-0-
$-0-
$-0-
$-0-
Other Long-Term Liabilities
$-0-
$-0-
$-0-
$-0-
$-0-
Total
$4,405,333
$89,560
$4,315,773
$-0-
$-0-
ITEM 7A.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A
ITEM 9A (T).
CONTROLS AND PROCEDURES
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 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.
Management’s Report on Internal Control over Financial Reporting
Management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in the Securities Exchange Act of 1934 Rule 13a-15(f). Internal control over financial reporting refers to the process designed by, or under the supervision of, the Company’s Chief Executive Officer and Chief Financial Officer, and effected by the Company’s Board of Directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, and includes those policies and procedures that:
•
Pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the Company’s assets;
•
Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorizations of the Company’s management and directors; and
•
Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s financial statements.
Under the supervision and with the participation of the Company’s management, including the Chief Executive Officer and the Chief Financial Officer, the Company’s management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2007 as required by the Securities Exchange Act of 1934 Rule 13a-15(c). In making this assessment, the Company’s management used the criteria set forth in the framework in “Internal Control - Integrated Framework” issued by the Committee of Sponsoring organizations of the Treadway Commission (“COSO”). Based on the evaluation conducted under the framework in “Internal Control - Integrated Framework,” issued by COSO the Company’s management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2007.
This report does not include an attestation report of the Company’s registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by the Company’s registered public accounting firm pursuant to temporary rules of the SEC that permit the Company to provide only management’s report in this Annual Report on Form 10-K.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness into future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Changes in Internal Controls
There have been no changes to the Company’s system of internal control over financial reporting during the year ended December 31, 2007 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.
ITEM 9B.
ITEM 9B.
OTHER INFORMATION
The Company’s 2008 Annual Meeting of Stockholders will be held on June 2, 2008 at 9:00 a.m. at the Homewood Suites by Hilton, 10935 Turkey Drive, Knoxville, Tennessee 37922. Proposals of stockholders sought to be presented at the 2008 annual meeting must be received in writing, by the Chief Executive Officer of the Company at the Company’s offices by
the close of business on April 4, 2008 in order to be considered for inclusion in the Company's proxy statement relating to that meeting.
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 2008 Annual Meeting of Stockholders (the “Proxy Statement”).
ITEM 10.
ITEM 10.
DIRECTORS AND EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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.
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.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
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, 2007.
Plan Category
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
(a)
Weighted-average
exercise price of
outstanding, options,
warrants and rights
(b)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
(c)
Equity compensation
plans approved by
security holders
2,441,000
$0.30
39,368
Equity compensation
plans not approved
by security holders10
n/a
Total
2,441,000
$0.30
39,638
_________________________
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. On February 1, 2008, the Company’s Board of Directors adopted further amendments to the Plan to increase the number of shares that may be issued under the Plan by 3,500,000 shares and to extend the Plan for another 10 years from October 24, 2010 to October 24, 2020. The Company’s shareholders will be requested to vote to approve these amendments at the upcoming Annual Meeting of the Company’s shareholders to be held on June 2, 2008.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
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.
ITEM 14.
PRINCIPAL ACCOUNTANTS FEES AND SERVICES
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
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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:
Exhibit Number
Description
3.1
Charter (Incorporated by reference to Exhibit 3.7 to the registrant’s registration statement on Form 10-SB filed August 7, 1997 (the “Form 10-SB”))
3.2
Articles of Merger and Plan of Merger (taking into account the formation of the Tennessee wholly-owned subsidiary for the purpose of changing the Company’s domicile and effecting reverse split) (Incorporated by reference to Exhibit 3.8 to the Form 10-SB)
3.3
Articles of Amendment to the Charter dated June 24, 1998 (Incorporated by reference to Exhibit 3.9 to the registrant’s annual report on Form 10-KSB filed April 15, 1999 (the “1998 Form 10-KSB”))
3.4
Articles of Amendment to the Charter dated October 30, 1998 (Incorporated by reference to Exhibit 3.10 to the 1998 Form 10-KSB)
3.5
Articles of Amendment to the Charter filed March 17, 2000 (Incorporated by reference to Exhibit 3.11 to the registrant’s annual report on Form 10-KSB filed April 14, 2000 (the “1999 Form 10-KSB”))
3.6
By-laws (Incorporated by reference to Exhibit 3.2 to the Form 10-SB)
3.7
Amendment and Restated By-laws dated May 19, 2005 (Incorporated by reference to the registrant’s annual report on Form 10-K for the year ended December 31, 2005)
4.1
Form of Rights Certificate Incorporated by reference to registrant’s statement on Form S-1 filed February 13, 2004 Registration File No. 333-109784 (the “Form S-1")
10.1
Natural Gas Sales Agreement dated November 18, 1999 between Tengasco, Inc. and Eastman Chemical Company (Incorporated by reference to Exhibit 10.10 to the registrant’s current report on Form 8-K filed November 23, 1999)
10.2
Amendment Agreement between Eastman Chemical Company and Tengasco, Inc. dated March 27, 2000 (Incorporated by reference to Exhibit 10.14 to the registrant’s 1999 Form 10-KSB)
10.3
Natural Gas Sales Agreement between Tengasco, Inc. and BAE SYSTEMS Ordnance Systems Inc. dated March 30, 2001 (Incorporated by reference to Exhibit 10.20 to the 2000 Form 10-KSB)
10.4
Tengasco, Inc. Incentive Stock Plan (Incorporated by reference to Exhibit 4.1 to the registrant’s registration statement on Form S-8 filed October 26, 2000)
10.5
Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated May 18, 2004 in the principal amount of $2,500,000 (Incorporated by reference to Exhibit 10.47 to the registrant’s quarterly report on Form 10-Q filed May 20, 2004)
10.6
Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated December 30, 2004 in the principal amount of $550,000 (Incorporated by reference from to Exhibit 10.19 to the registrant’s Annual Report on Form 10-K filed March 31, 2005)
10.7
Asset Purchase Agreement dated March 4, 2005 between Tengasco, Inc. and Bear Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 the registrant’s current report on Form 8-K dated March 9, 2005 (the “March 9, 2005 Form 8-K”)
10.8
Assignment and Bill of Sale between Tengasco, Inc. and Bear Petroleum, Inc. (Incorporated by reference to Exhibit 10.2 to the March 9, 2005 Form 8-K)
10.9
Amended and Restated Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated May 19, 2005 in the principal amount of $700,000 ((Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated May 23, 2005)
10.10
Amendment to the Tengasco, Inc. Stock Incentive Plan dated May 19, 2005 (Incorporated by reference to Exhibit 4.2 to the registrant’s registration statement on Form S-8 filed June 3, 2005)
10.11
Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated August 22, 2005 in the principal amount of $1,814,000 (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated August 22, 2005 (the “August 22, 2005 8-K”))
10.12
Amended and Restated Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation dated August 18, 2005 in the principal amount of $700,000 (Incorporated by reference to Exhibit 10.2 to the August 22, 2005 8-K.)
10.13
Subscription Agreement of Hoactzin Partners, L.P. for a 94.275% working interest in the Company’s twelve well drilling program on its Kansas Properties. (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated October 5, 2005)
10.14
Loan and Security Agreement dated as of June 29, 2006 between Tengasco, Inc. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated June 29, 2006)
10.15*
Subscription Agreement of Hoactzin Partners, L.P. for the Company’s ten well drilling program on its Kansas Properties dated August 3, 2007.
10.16*
Agreement and Conveyance of Net Profits Interest dated September 17, 2007 between Manufactured Methane Corporation as Grantor and Hoactzin Partners, LP as Grantee.
10.17*
Agreement for Conditional Option for Exchange of Net Profits Interest for Convertible Preferred Stock dated September 17, 2007 between Tengasco, Inc., as Grantor and Hoactzin Partners, L.P., as Grantee.
10.18*
Assignment of Notes and Liens Dated December 17, 2007 between Citibank, N.A., as Assignor, Sovereign Bank, as Assignee and Tengasco, Inc., Tengasco Land & Mineral Corporation and Tengasco Pipeline Corporation as Debtors
10.19
Employment Agreement dated December 18, 2007 between Tengasco, Inc. and Charles Patrick McInturff (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated December 18, 2007)
10.20*
Management Agreement dated December 18, 2007 between Tengasco, Inc. and Hoactzin Partners, L.P.
Code of Ethics (Incorporated by reference to Exhibit 14 to the registrant’s annual report on Form 10-K filed March 30, 2004)
17.1
Letter of resignation of Clarke H. Bailey as a Director of the Company dated March 27, 2007 (Incorporated by reference to Exhibit 17.1 to the registrant’s current report on Form 8-K dated March 27, 2007)
21*
List of subsidiaries
23.1*
Consent of LaRoche Petroleum Consultants, Ltd.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a)
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a)
32.1*
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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 31, 2008
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in their capacities and on the dates indicated.
Signature
Title
Date
s/Jeffrey R. Bailey
Jeffrey R. Bailey
Director;
Chief Executive Officer
March 31 , 2008
s/Matthew K. Behrent
Matthew K. Behrent
Director
March 31, 2008
s/John A. Clendening
John A. Clendening
Director
March 31, 2008
s/Carlos P. Salas
Carlos P. Salas
Director
March 31, 2008
s/Peter E. Salas
Peter E. Salas
Director
March 31, 2008
s/Mark A. Ruth
Mark A. Ruth
Principal and Financial
Accounting Officer
March 31, 2008
Consolidated Financial Statements
Years Ended December 31, 2007, 2006 and 2005
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Consolidated Balance Sheets
-
Consolidated Income Statements
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Tengasco, Inc. and Subsidiaries
Knoxville, Tennessee
We have audited the accompanying consolidated balance sheets of Tengasco, Inc. and Subsidiaries as of December 31, 2007 and 2006 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Tengasco, Inc. and Subsidiaries as of December 31, 2007 and 2006 and the results of their operations and cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.
/s/ Rodefer Moss & Co, PLLC
Knoxville, Tennessee
March 27, 2008
Tengasco, Inc. and Subsidiaries
Consolidated Balance Sheets
December 31,
Assets
Current
Cash and cash equivalents
$ 2,226,839
$ 369,665
Accounts receivable
1,057,148
719,840
Participant receivables
49,872
13,008
Inventory
460,365
550,522
Other current assets
11,056
11,056
Total current assets
3,805,280
1,664,091
Restricted cash
120,500
120,500
Loan fees
223,733
237,738
Oil and gas properties, net (on the basis
of full cost accounting)
13,209,601
12,703,629
Pipeline facilities, net of accumulated
depreciation of $3,423,099 and $2,879,099
12,916,667
13,460,667
Other property and equipment, net
256,058
267,713
Deferred Tax Asset
2,100,000
-
Methane Project
1,649,710
-
$ 34,281,549
$ 28,454,338
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Balance Sheets
December 31,
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long term debt
$ 57,887
$ 65,267
Accounts payable
903,238
687,475
Accrued interest payable
10,005
8,432
Other accrued liabilities
360,674
30,410
Total current liabilities
1,331,804
791,584
Asset retirement obligations
531,101
512,015
Long term debt, less currentmaturities
4,315,773
2,730,534
Total liabilities
6,178,678
4,034,133
Stockholders’ equity
Common stock, $.001 par value; authorized 100,000,000 shares;
59,155,750 and 59,003,284 shares issued and outstanding
59,156
59,004
Additional paid-in capital
54,689,525
54,517,333
Accumulated deficit
(26,645,810)
(30,156,132)
Total Stockholders’ equity
28,102,871
24,420,205
$ 34,281,549
$ 28,454,338
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Income Statements
Years ended December 31,
Revenues and other income
Oil and gas revenues
$ 9,300,144
$ 8,896,036
$ 7,076,790
Pipeline transportation revenues
51,492
87,822
94,911
Interest Income
16,988
17,823
1,175
Total revenues and other income
9,368,624
9,001,681
7,172,876
Costs and expenses
Production costs and taxes
4,322,833
3,287,233
3,046,460
Depreciation, depletion and amortization
1,631,468
1,911,416
1,605,043
General and administrative
1,417,001
1,293,109
1,322,616
Interest expense
333,198
168,590
472,655
Public relations
21,605
26,037
30,020
Professional fees
232,197
173,932
263,800
Total costs and expenses
7,958,302
6,860,317
6,740,594
Net Operating Income
1,410,322
2,141,364
432,282
Deferred Tax Benefit
2,100,000
-
-
Gain on Preferred Stock
-
-
655,746
Net Income
$ 3,510,322
$ 2,141,364
$ 1,088,028
Net Income per share
Basic and diluted:
Operations
$ 0.06
$ 0.04
$ 0.02
Total
$ 0.06
$ 0.04
$ 0.02
Shares used in computing earnings per share
Basic
59,117,176
58,851,883
52,019,051
Diluted
60,827,224
60,364,797
52,659,051
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(1.)
Summary of Significant Accounting Policies
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, later changed to Onasco Companies, Inc. In 1995, the Company changed its name from Onasco Companies, Inc. to Tengasco, Inc., by merging into Tengasco, Inc., a Tennessee corporation, formed by the Company solely for this purpose.
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. Emphasis is also placed on pipeline and other infrastructure facilities to provide transportation services. The Company utilizes seismic technology to improve the recovery 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 2007, the Kansas Properties produced an average of 14,860 gross barrels of oil per month.
The Company’s activities in 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 2007, the Company produced an average of 347 thousand cubic feet of natural gas per day and 573 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 treatment technologies for the extraction of methane gas from nonconventional sources for delivery through the nation’s existing natural gas pipeline system, including the Company’s TPC pipeline system in Tennessee for eventual sale to natural gas customers.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Basis of Presentation
The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America, which contemplate continuation of the Company as a going concern and assume realization of assets and the satisfaction of liabilities in the normal course of business.
The consolidated financial statements include the accounts of the Company, Tengasco Pipeline Corporation, Tennessee Land & Mineral Corporation and Manufactured Methane Corporation. All intercompany balances and transactions have been eliminated.
Use of Estimates
The accompanying consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The actual results could differ from those estimates.
Revenue Recognition
The Company uses the sales method of accounting for natural gas and oil revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. Natural gas meters are placed at the customers’ locations and usage is billed monthly.
Cash and Cash Equivalents
The Company considers all investments with a maturity of three months or less when purchased to be cash equivalents.
Inventory
Inventory consists of crude oil in tanks and is carried at lower of cost or market value.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Oil and Gas Properties
The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all productive and nonproductive 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, delay rentals and the costs of drilling, completing, equipping and plugging oil and gas wells. 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 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 Company currently has $3,110,768 in unevaluated properties as of December 31, 2007. 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 has determined its reserves based upon reserve reports provided by Ryder Scott Company, Petroleum Consultants in 2005 , and by LaRoche Petroleum Consultants Ltd. in 2006 and 2007.
The capitalized oil and gas properties, 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. The Company has adopted an SEC accepted method of calculating the full cost ceiling test whereby the liability recognized under Statement of Financial Accounting Standard No. 143 (“SFAS”) “Accounting for Asset Retirement Obligation” (“SFAS 143”) is netted against property cost and the future abandonment obligations are included in estimated future net cash flows. No ceiling write-downs were recorded in 2007, 2006, or 2005.
Pipeline Facilities
Phase I of the pipeline was completed during 1999. Phase II of the pipeline was completed on March 8, 2001. Both phases of the pipeline were placed into service upon completion of Phase II. The pipeline is being depreciated over its estimated useful life of 30 years beginning at the time it was placed in service.
Other Property and Equipment and Long - Lived Assets
Other property and equipment are carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from three to seven years. Long-lived assets (other than oil and gas properties) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
When evidence indicates that operations will not produce sufficient cash flows to cover the carrying amount of the related asset, a permanent impairment is recorded to adjust the asset to fair value. At December 31, 2007, management believes that carrying amounts of all of the Company’s long-lived assets will be fully recovered over the course of the Company’s normal future operations.
Stock-Based Compensation
The Company recorded $100,877 in 2007, $128,197 in 2006 and $84,030 in compensation expense in 2005 upon the Company’s adoption of SFAS 123 (R) in 2005.
Accounts Receivable
Senior management reviews accounts receivable on a monthly basis to determine if any receivables will potentially be uncollectible. Based on the information available to us, the Company believes no allowance for doubtful accounts as of December 31, 2007 and 2006 is necessary. However, actual write-offs may occur.
Income Taxes
The Company accounts for income taxes using the “asset and liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets arise primarily from net operating loss carry-forwards. Management evaluates the likelihood of realization for such assets at year-end providing a valuation allowance for any such amounts not likely to be recovered in future periods. The Company currently has a net operating loss carry forward of 21,100,000.
Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. At times, such cash in banks is in excess of the FDIC insurance limit.
The Company’s primary business activities include oil and gas sales to several customers in the states of Kansas and Tennessee. The related trade receivables subject the Company to a concentration of credit risk within the oil and gas industry.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company is presently dependent upon a small number of customers for the sale of gas from the Swan Creek Field, principally Eastman Chemical Company and other industrial customers in the Kingsport area with which the Company may enter into gas sales contracts.
The Company has entered into contracts to supply two manufacturers with natural gas from the Swan Creek Field (Tennessee) through the Company’s pipeline. These customers are the Company’s primary customers for natural gas sales. Additionally, the Company sells a majority of its crude oil primarily to two customers, one each in Tennessee and Kansas. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it could have a significant adverse effect on the Company’s projected results of operations.
In 2007, the Company received 91.4 percent of its revenues from Customer A; 4.9 percent of its revenues from Customer B; and 3.7 percent of its revenues from Customer C.
In 2006, the Company received 85.7 percent of its revenues from Customer A; 10.1 percent of its revenues from Customer B.
In 2005, the Company received 74.6 percent of its revenues from Customer A; 18.6 percent of its revenues from Customer B.
In each of the years 2005 through 2007, the identity of the customers indicated above as either A, B or C was the same from year to year, although the percentage of revenues varied from year to year for those customers.
In accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share” (“SFAS 128”), basic income per share is based on 59,117,176, 58,851,883 and 52,019,051 weighted average shares outstanding for the years ended December 31, 2007, December 31, 2006 and December 31, 2005 respectively. Diluted earnings per common share are computed by dividing income available to common shareholders by the weighted average number of shares of common stock outstanding during the period increased to include the number of additional shares of common stock that would have been outstanding if the dilutive potential shares of common stock had been issued. The dilutive effect of outstanding options and warrants is reflected in diluted earnings per share.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The number of dilutive shares outstanding is 1,710,048 for 2007, 1,512,914 for 2006 and 640,000 for 2005. These are related to options and warrants.
Fair Values of Financial Instruments
Fair values of cash and cash equivalents, investments and short-term debt approximate their carrying values due to the short period of time to maturity. Fair values of long-term debt are based on quoted market prices or pricing models using current market rates, which approximate carrying values.
(2.) Recent Accounting Pronouncements
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 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. The adoption of FIN 48 had no impact on our results of operations or financial position. The Company currently has open tax return periods beginning with December 31, 2004 through December 31, 2007.
In September 2006, the Securities and Exchange Commission staff published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The Company adopted SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. It defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurement
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. It clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company continues to evaluate the impact the adoption of this statement could have on its financial condition, results of operations and cash flows.
In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities - as amended (“SFAS 159”). SFAS 159 permits entities to elect to report eligible financial instruments at fair value subject to conditions stated in the pronouncement including adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial reporting by mitigating volatility in earnings related to current reporting requirements. The Company is considering the applicability of SFAS 159 and will determine if adoption is appropriate. The effective date for SFAS 159 is for fiscal years beginning after November 15, 2007.
In October, 2005 the Company accepted an exchange from 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. to fund the Company’s cash exchange to holders of its Series A, B and C Preferred Stock.
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 continuing to produce 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, 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, all well-drilling obligations of the Company under both the Eight Well and Twelve Well Programs with former preferred stockholders as participants have been satisfied.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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. 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.
On September 17, 2007, the Company entered into a drilling program with Hoactzin for ten wells consisting of approximately three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas Properties (the “Program”). Under the terms of the Program, Hoactzin was to pay the Company $400,000 for each well in the Program completed as a producing well and $250,00 per drilled well that was non-productive. The terms of Program also provide that Hoactzin will receive all the working interest in the ten wells in the Program, but will pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses. This is referred to as a management fee but as defined is in the nature of a net profits interest. The fee paid to the Company by Hoactzin will increase to 85% of working interest revenues when net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”). The Company will account for funds received for interests in the Program as an offset to oil and gas properties.
As of the date of this Report, the Company has drilled all ten wells in the Program. Of the ten wells drilled, nine were completed as oil producers and are currently producing approximately 84 barrels per day in total. Hoactzin paid a total of $3,850,000 for its interest in the Program resulting in the Payout Point being determined as $5,215,595. The amount paid by Hoactzin for its interest in the Program wells exceeded the Company’s actual drilling costs of approximately $2.8 million for the ten wells by more than $1 million.
Although production level of the Program wells will decline with time in accordance with expected decline curves for these types of well, based on the drilling results of the Program wells and the current price of oil, the Program wells are expected to reach the Payout Point in approximately four years solely from the oil revenues from the wells. However, under the terms of its agreement with Hoactzin reaching the Payout Point has been accelerated by Hoactzin agreeing to apply 75% of the net proceeds it receives from the methane extraction project being developed by the Company’s wholly-owned subsidiary, Manufactured Methane Corporation, at the Carter Valley, Tennessee landfill to the Payout Point. (The methane extraction project is discussed in greater detail below.) Those methane project proceeds when applied will result in the Payout Point being achieved sooner than the estimated four year period based solely upon revenues from the Program wells.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
On December 18, 2007, the Company entered into a Management Agreement with Hoactzin. On that same date, the Company also entered into an agreement with Charles Patrick McInturff employing him as a Vice-President of the Company. Pursuant to the Management Agreement with Hoactzin, Mr. McInturff’s duties while he is employed as Vice-President of the Company will include the management on behalf of Hoactzin of its working interests in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As consideration for the Company entering into the Management Agreement, Hoactzin has agreed that it will be responsible to reimburse the Company for the payment of one-half of Mr. McInturff’s salary, as well as certain other benefits he receives during his employment by the Company. In further consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin has granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or work-over activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement. The term of the Management Agreement is the earlier of the date Hoactzin sells its interests in its managed properties or 5 years.
The following table sets forth information concerning the Company’s oil and gas properties:
December 31,
Oil and gas properties, at cost
18,856,487
$ 18,745,834
Unevaluated properties
3,110,768
1,880,811
Accumulation depreciation,
depletion and amortization
(8,757,654)
(7,923,016)
Oil and gas properties, net
13,209,601
$ 12,703,629
During the years ended December 31, 2007, 2006 and 2005 the Company recorded depletion expense of $834,638, $1,144,711 and $902,131 in 2005.
In 1996, the Company began construction of a 65-mile gas pipeline (1) connecting the Swan Creek development project to a gas purchaser and (2) enabling the Company to develop gas transportation business opportunities in the future. Phase I, a 30-mile portion of the pipeline, was completed in 1998. Phase II of the pipeline, the remaining 35 miles, was completed in March 2001. The estimated useful life of the pipeline for depreciation purposes is 30 years. The Company recorded $544,000, $544,000 and $536,000, in depreciation expense related to the pipeline for the years ended December 31, 2007, 2006 and 2005, respectively.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
In January 1997, the Company entered into an agreement with the Tennessee Valley Authority (“TVA”) whereby the TVA allows the Company to bury the pipeline within the TVA’s transmission line rights-of-way. In return for this right, the Company paid $35,000 and agreed to annual payments of approximately $6,200 for 20 years.
This agreement expires in 2017 at which time the parties may renew the agreement for another 20-year term in consideration of similar inflation-adjusted payment terms.
Other property and equipment consisted of the following:
December 31
Depreciable Life
Machinery and equipment
5-7 yrs
$ 830,734
$ 771,767
Vehicles
2-5 yrs
487,176
521,824
Other
5 yrs
63,734
63,734
Total
1,381,644
1,357,325
Less accumulated depreciation
(1,125,586)
(1,089,612)
Other property and equipment - net
$ 256,058
$ 267,713
The Company uses the straight-line method of depreciation ranging from two years to seven years, depending on the asset life.
Long-term debt to unrelated entities consisted of the following:
December 31,
Note payable to a financial institution, with interest payment only until maturity.
(See Notes 15 & 16)
$4,200,000
$ 2,600,000
Installment notes bearing interest at the rate of 5.5% to 8.25% per annum collateralized by vehicles with monthly payments including interest of approximately $10,000 due through 2010.
173,660
195,801
Total long-term debt
4,373,660
2,795,801
Less current maturities
(57,887)
(65,267)
Long-term debt, less current
maturities
4,315,773
$ 2,730,534
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
8.
Commitments and Contingencies
The Company is a party to lawsuits in the ordinary course of its business. The Company does not believe that it is probable that the outcome of any individual action will have a material adverse effect, or that it is likely that adverse outcomes of individually insignificant actions will be significant enough, in number or magnitude, to have in the aggregate a material adverse effect on its financial statements.
In the ordinary course of business the Company has entered into office leases which have remaining term of 6 months. Approximate future minimum lease payments to be made under non-cancelable operating leases in 2008 are $31,673.
Office rent expense for each of the three years ended December 31, 2007, 2006 and 2005 was approximately $63,346, $63,346, and $ 83,332 respectively.
9.
Cumulative Convertible Redeemable
On August 22, 2005 all holders of the Company's Series B and C Cumulative Convertible Preferred Stock (the "Series B and Series C shares"), having a total aggregate value of $5,113,045 consisting of face value, dividends, and interest exchanged all rights under their Series B and C shares for cash or for the Company's common stock. As a result of the exchange, as of August 22, 2005 the Company no longer had any holders of Series B or C preferred stock and no further obligations under any Series B or C shares. Holders of approximately 53.2% of the face value of outstanding Series B and C shares exchanged their preferred shares having an aggregate value of $2,721,140 for cash payments totaling $1,814,184. The Company obtained the funds for this exchange primarily from proceeds of a loan of $1,814,000 from Dolphin. The loan from Dolphin was evidenced by a secured promissory note dated August 22, 2005 bearing 12% interest per annum payable interest only monthly until the principal amount of the note was to become due on December 31, 2005. A second option offered to the Series B and C holders 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. All of the holders, including Dolphin, of the remaining aggregate value of $2,391,905 or 46.8% of the Series B and C shares selected this option. As a result, a total of 9,567,620 shares of the Company's common stock were issued to those holders. 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.
In total, the Company recorded a gain during 2005 from the exchange of Series A, B and C shares for cash and stock of $655,746, the difference between the carrying amount and the cash settlement amount and the stock issued.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company follows the requirements of SFAS 143. Among other things, SFAS 143 requires entities to record a liability and corresponding increase in long-lived assets for the present value of material obligations associated with the retirement of tangible long-lived assets. Over the passage of time, accretion of the liability is recognized as an operating expense and the capitalized cost is depleted over the estimated useful life of the related asset. Additionally, SFAS 143 required that upon initial application of these standards, the Company must recognize a cumulative effect of a change in accounting principle corresponding to the accumulated accretion and depletion expense that would have been recognized had this standard been applied at the time the long-lived assets were acquired or constructed. The Company’s asset retirement obligations relate primarily to the plugging, dismantling and removal of wells drilled to date. The Company’s calculation of Asset Retirement Obligation used a credit-adjusted risk free rate of 12%, an estimated useful life of wells ranging from 30-40 years, estimated plugging and abandonment cost range from $5,000 per well to $10,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions.
On March 4, 2005 the Company sold its Kansas gas wells, and consequently the asset and the corresponding liability relating to asset retirement obligations on these wells were extinguished. The asset account was credited for $60,998 and the liability was removed in the amount of $133,397, creating a gain on the extinguishment of future obligations in the amount of $72,399, which was credited to interest expense.
The following is a roll-forward of activity impacting the asset retirement obligation for the year ended December 31, 2007:
Balance, December 31, 2005
$ 566,968
Accretion expense
42,340
Liabilities Settled
(97,293)
Balance, December 31, 2006
$ 512,015
Accretion expense
70,929
Liabilities Settled
(51,843)
Balance, December 31, 2007
$ 531,101
In October 2000, the Company approved a Stock Incentive Plan. The Plan is effective for a ten-year period commencing on October 25, 2000 and ending on October 24, 2010. The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to participants under the plan shall not exceed 3,500,000. Options are not transferable, are exercisable for 3 months after voluntary
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
resignation from the Company, and terminate immediately upon involuntary termination from the Company. The purchase price of shares subject to this plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the fair market value of such shares on the date of grant. Furthermore, a participant in the Plan may not, immediately prior to the grant of an Incentive Stock Option hereunder, own stock in the Company representing more than ten percent of the total voting power of all classes of stock of the Company unless the per share option price specified by the Board for the Incentive Stock Options granted such a participant is at least 110% of the fair market value of the Company’s stock on the date of grant and such option, by its terms, is not exercisable after the expiration of 5 years from the date such stock option is granted.
Stock option activity in 2007, 2006 and 2005 is summarized below:
The following table summarizes information about stock options outstanding and exercisable at December 31, 2006:
Options Outstanding
Options Exercisable
Weighted Average
Exercise Price
Shares
Weighted Average
Remaining
Contractual
Life (years)
Shares
$ 0.27
2,251,000
2.33
1,357,000
$ 0.58
110,000
3.05
110,000
$ 0.81
80,000
3.93
80,000
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The weighted average fair value per share of options granted during 2006 and 2005 range from $0.15 to $0.32, calculated using the Black-Scholes Option-Pricing model. No options were granted in 2007.
Compensation expense of $84,030 related to stock options was recognized in 2005 and $128,197 in 2006 and 100,877 in 2007.
The fair value of stock options used to compute pro forma net loss and loss per share disclosures is the estimated present value at grant date using the Black-Scholes option-pricing model with the following weighted average assumptions for 2006 and 2005: expected volatility of 60% for 2006, and 2005; a risk free interest rate of 3.67% in 2006 and 2005; and an expected option life of 2.5 years for 2006 and 2005.
The Company has taxable income for the periods ending December 31, 2007, December 31, 2006 and December 31, 2005.
A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows:
December 31,
Statutory rate
34%
34%
34%
Tax (benefit)/expense
at statutory rate
1,193,000
$ 728,000
$ 370,000
State income
tax (benefit)/expense
140,000
85,000
43,000
Other
3,000
3,000
3,000
Non-deductible interest
-
Increase/(decreases)in deferred tax asset valuation allowance
(3,436,000)
(816,000)
(416,000)
Total income tax provision (benefit)
(2,100,000)
-
-
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company’s deferred tax assets and liabilities are as follows:
December 31
Deferred tax assets:
Net operating loss carryforward
$7,314,000
$ 8,700,000
$ 9,616,000
Capital loss carry forward
263,000
263,000
263,000
Total deferred tax assets
7,577,000
8,963,000
9,879,000
Deferred tax liability:
Basis difference in pipeline
250,000
300,000
400,000
Total deferred liability
250,000
300,000
400,000
Total net deferred taxes
7,327,000
8,663,000
9,479,000
Valuation allowance
(5,227,000)
(8,663,000)
(9,479,000)
Net deferred tax asset
$2,100,000
-
-
As of December 31, 2007, Management, using the “more likely than not” criteria for recognition, elected to recognize a deferred tax asset of $2.1 million. The recognition of the deferred tax asset in 2007 relates to net operating loss carryforwards and will provide a better matching of income tax expense with taxable income in future periods. The current provision reflects the recognition of $1,336,000 current income tax benefit (fully offset by the current provision related to 2007 taxable income) and $2,100,000 in benefit relating to future periods.
No income tax expense was recognized for the years ended December 31, 2006 or December 31, 2005 because deferred tax benefits, derived from the Company’s prior net operating losses, were previously fully reserved and were being offset against tax liabilities that would otherwise arise from the results of current operations. Management continuously estimates the realization of the Company’s deferred tax assets based on its anticipation of the likely timing and adequacy of future net income, after taking into consideration the increased uncertainty attributed to a lengthening horizon before the projected realization of future deferred assets.
As of December 31, 2007, the Company had net operating loss carry-forwards of approximately $21,100,000 which will expire between 2011 and 2023 if not utilized.
The Company paid approximately $262,268, $126,250, and $524,000, for interest in 2007, 2006 and 2005, respectively. No interest was capitalized in 2007, 2006 or 2005. No income taxes were paid in 2007, 2006, or 2005.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
On May 10, 2004 the Court entered its final order approving the fairness of the settlement to the class, dismissing the action pursuant to a Settlement Stipulation, and fully releasing the claims of the class members in Paul Miller v. M. E. Ratliff and Tengasco, Inc., No. 3:02-CV-644 in the United States District Court for the Eastern District of Tennessee, Knoxville, Tennessee. This action sought certification of a class action to recover on behalf of a class of all persons who purchased shares of the Company’s common stock between August 1, 2001 and April 23, 2002, unspecified damages allegedly caused by violations of the federal securities laws. In January, 2004 all parties reached a settlement subject to court approval. The Court entered its order approving the settlement on May 10, 2004. Under the settlement, the Company paid into a settlement fund the amount of $37,500 to include all costs of administration, contributed 150,000 shares of stock of Miller Petroleum, Inc. owned by the Company and issued 300,000 warrants to purchase a share of the Company’s common stock for a period of three years from date of issue at $1 per share subject to adjustments. The Rights Offering adjusted this price to $0.45 per share. These Warrants expire on September 12, 2008. The Miller Petroleum, Inc. investment had a net carrying value of $60,000 and a cumulative other comprehensive loss of $90,000, which was reversed from cumulative other comprehensive loss and recognized as a realized loss during the third quarter of 2004.
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 an initial 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. The facility has standard loan covenants such as current ratios, interest coverage ratios etc, with which the Company is in compliance.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
$1.393 million of the $2.6 million loan proceeds were used by the Company on June 29, 2006 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 12-well Kansas drilling program for Hoactzin. The Company incurred loan closing costs consisting of legal fees, mortgage taxes, commissions and bank fees totaling $285,224. This amount will be amortized over the term of the note and its successor (See Note 16).
On April 19, 2007 the Company borrowed an additional sum of $700,000 from Citibank, N.A. under its existing revolving credit facility dated June 29, 2006. The additional borrowing resulted from an increase in the Company’s borrowing base under the Citibank credit facility from $2.6 million to $3.3 million based upon Citibank’s periodic review of the Company’s borrowing base. With the additional borrowing, the Company has borrowed the full amount of its $3.3 million borrowing base under the revolving Citibank credit facility. Repayment of this additional sum is subject to the terms and conditions of the Citibank credit facility. The additional amount borrowed will be used for further development of the Company’s producing properties.
On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by the Company.
Under the facility as assigned to Sovereign, 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 $20 million or the Company’s borrowing base in effect from time to time. The Company’s initial borrowing base with Sovereign was set at $7.0 million, an increase from its borrowing base of $3.3 million with Citibank prior to the assignment.
The Company’s initial borrowing on December 17, 2007 under its new facility with Sovereign was approximately $4.2 million which will bear interest at a floating rate equal to prime as published in the Wall Street Journal plus 0.25% resulting in a current interest rate of approximately 7.5%. Interest only is payable during the term of the loan and the principal balance of the loan is due December 31, 2010. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane Project assets.
The Company used a portion of the $4.2 million borrowed from Sovereign to pay off the funds it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign was used to pay bank fees and attorney fees relating to the assignment in the amount of approximately $75,000 and the balance of approximately $825,000 was used to pay a portion of the purchase price for equipment to be utilized in the Methane Project currently under construction in Carter Valley, Tennessee by MCC, the Company’s wholly-owned subsidiary.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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 was thereafter assigned to the Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) and provides that MMC will purchase all the naturally produced gas stream presently being collected and flared at the municipal solid waste landfill in Carter Valley 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 (the “Methane Project”).
MCC has placed equipment orders for its first stage of process equipment (cleanup and carbon dioxide removal) and the second stage of process equipment (nitrogen rejection) for the Methane Project. It is anticipated that the total costs for the Project including pipeline construction, will be approximately $4.1 million including costs for compression and interstage controls. The costs of the Methane Project to date have been funded primarily by (a) the money received by the Company from Hoactzin to purchase its interest in the Ten Well Program which exceeded the Company’s actual costs of drilling the wells in that Program by more than $1 million (b) cash flow from the Company’s operations in the amount of approximately $1 million and (c) $825,000 of the funds the Company borrowed from its credit facility with Sovereign Bank. The Company anticipates that most of the remaining balance of the Methane Project costs will be paid from the Company’s cash flow.
The Company anticipates that the equipment ordered by MMC will be manufactured and delivered to allow operations to begin in mid-2008 after equipment installation, testing, and startup procedures are begun. Commercial deliveries of gas will begin when the equipment is installed and tested and the pipeline is constructed. Upon commencement of operations, the methane gas produced by the project facilities will be mixed in the Company’s pipeline and delivered and sold to Eastman Chemical Company (“Eastman”) under the terms of the Company’s existing natural gas purchase and sale agreement. 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 substantially increase the current volumes of natural gas being delivered to Eastman by the Company from its Swan Creek field. At an assumed sales price of gas of $7 per MMBtu, near the average natural gas price received by the Company in 2007, the anticipated net revenues to the Company would be approximately $800,000 per year from the Methane Project based on anticipated volumes and expenses. The gas supply from this project is projected to grow over the years as the underlying operating
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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.
As part of the Methane Project agreement, the Company agreed to install a new force-main water drainage line for Allied Waste Industries, an affiliate of BFI, the landfill owner, in the same two-mile pipeline trench as the gas pipeline needed for the project, reducing overall costs and avoiding environmental effects to private landowners resulting from multiple installations of pipeline. Allied Waste will pay the additional costs for including the water line. Construction of the gas pipeline needed to connect the facility with the Company’s existing natural gas pipeline began in January 2008. As a certificated utility, the Company’s pipeline subsidiary, TPC, requires no additional permits for the gas pipeline construction. The Company currently anticipates that pipeline construction will be concluded approximately the same time as equipment deliveries and installations occur or in the May to June 2008 time period, subject to weather delays during wintertime construction.
On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program, pursuant to a separate agreement with the Company was conveyed a 75% net profits interest in the Methane Project. When the Methane Project comes online, the revenues from the Project received by Hoactzin will be applied towards the determination of the Payout Point (as defined above) for the Ten Well Program. When the Payout Point is reached from either the revenues from the wells drilled in the Program or the Methane Project or a combination thereof, Hoactzin’s net profits interest in the Methane Project will decrease to a 7.5% net profits interest. The Company believes that the application of revenues from the methane project to reach the Payout Point will rapidly accelerate reaching the Payout Point. Those excess funds provided by Hoactzin were used to pay for approximately $1,000,000 of equipment required for the Methane Project, or about 25% of the Project’s capital costs. The availability of the funds provided by Hoactzin eliminated the need for the Company to borrow those funds, to have to pay interest to any lending institution making such loans or to dedicate Company revenues or revenues from the Methane Project to pay such debt service. Accordingly, the grant of a 7.5% interest in the Methane Project to Hoactzin was negotiated by the Company as a favorable provision to the Company in the overall transaction.
As security required by Tennessee oil and gas regulations, the Company placed $120,500 in a Certificate of Deposit to cover future asset retirement obligations for the Company’s Tennessee wells.
The following table sets forth for the fiscal periods indicated, selected consolidated financial data.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Fiscal Year Ended 2007
First Quarter
Second Quarter
Third Quarter(a)
Fourth Quarter(a)
Revenues
$1,772,400
$2,220,439
$2,375,229
$3,000,556
Net loss/income
($209,165)
$ 330,756
$1,580,662
$1,808,069
Net loss/income attributable to common stockholders
($209,165)
$330,756
$1,580,662
$1,808,069
Income/loss per common share
$ 0.00
$ .01
$ 0.03
$ 0.03
Fiscal Year Ended 2006
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Revenues
$ 2,098,969
$ 2,354,736
$ 2,251,274
$ 2,296,702
Net loss/income
316,347
720,769
519,094
585,154
Net loss/income attributable to common stockholders
$ 316,347
$ 720,769
$ 519,094
$ 585,154
Income/loss per common share
$ 0.01
$ 0.01
$
0.01
$
0.01
(a)
The company recorded 1.1 million in deferred tax asset in the third quarter of 2007 and 1.0 million in the fourth quarter of 2007.
20. Supplemental Oil and Gas Information (unaudited)
Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserve quantities, as well as future production and discounted cash flows before income taxes, were determined by Ryder Scott Company, L.P. as of December 31, 2005, The reserves were estimated by LaRoche Petroleum Consultants Ltd. in 2006 and 2007.
Oil and Gas Related Costs
The following table sets forth information concerning costs related to the Company’s oil and gas property acquisition, exploration and development activities in the United States during the years ended:
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Property acquisitions
Proved
200,000
Unproved
-
Less -proceeds from
Sales of properties
-
-
$ (2,651,770)
Development Cost
4,990,611
4,172,462
402,876
5,190,611
$ 4,172,462
$ (2,248,894)
Results of Operations from Oil and Gas Producing Activities
The following table sets forth the Company’s results of operations from oil and gas producing activities for the years ended:December 31,
Revenues
9,300,144
$ 8,896,036
$ 7,076,790
Production costs and taxes
(4,160,488)
(3,145,244)
(2,956,307)
Depreciation, depletion and amortization
(834,638)
(1,144,711)
(902,132)
Income from oil and gas producing activities
4,305,018
$ 4,606,081
$ 3,218,351
In the presentation above, no deduction has been made for indirect costs such as corporate overhead or interest expense. No income taxes are reflected above due to the Company’s operating tax loss carry-forwards.
Oil and Gas Reserves
The following table sets forth the Company’s net proved oil and gas reserves at December 31, 2007, 2006 and 2005 and the changes in net proved oil and gas reserves for the years then ended. Proved reserves represent the quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future years from known reservoirs under existing economic and operating conditions. Reserves are measured in barrels (bbls) in the case of oil, and units of one thousand cubic feet (Mcf) in the case of gas.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following two tables:
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using current sales prices, along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The average prices used at December 31, 2007, 2006, and 2005 were $85.44, $56.50, and $55.81, per barrel of oil and $7.21, $8.33 and $11.31 per MCF of gas, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
Operating costs and production taxes are estimated based on current costs with respect to producing properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable net operating loss carry-forwards, for both regular and alternative minimum tax. For the years ended December 31, 2007, 2006 and 2005 the Company’s available net operating loss carry forwards offset all tax effects applicable to the discounted future net cash flows.
The future net revenue information assumes no escalation of costs or prices, except for gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
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, 2007.
Plan Category
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights
(a)
Weighted-average
exercise price of
outstanding, options,
warrants and rights
(b)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in column
(a))
(c)
Equity compensation
plans approved by
security holders
2,441,000
$0.30
39,368
Equity compensation
plans not approved
by security holders10
n/a
Total
2,441,000
$0.30
39,638
_________________________
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. On February 1, 2008, the Company’s Board of Directors adopted further amendments to the Plan to increase the number of shares that may be issued under the Plan by 3,500,000 shares and to extend the Plan for another 10 years from October 24, 2010 to October 24, 2020. The Company’s shareholders will be requested to vote to approve these amendments at the upcoming Annual Meeting of the Company’s shareholders to be held on June 2, 2008.
ITEM 13.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
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.
ITEM 14.
ITEM 14.
PRINCIPAL ACCOUNTANTS FEES AND SERVICES
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
ITEM 15.
ITEM 15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
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:
Exhibit Number
Description
3.1
Charter (Incorporated by reference to Exhibit 3.7 to the registrant’s registration statement on Form 10-SB filed August 7, 1997 (the “Form 10-SB”))
3.2
Articles of Merger and Plan of Merger (taking into account the formation of the Tennessee wholly-owned subsidiary for the purpose of changing the Company’s domicile and effecting reverse split) (Incorporated by reference to Exhibit 3.8 to the Form 10-SB)
3.3
Articles of Amendment to the Charter dated June 24, 1998 (Incorporated by reference to Exhibit 3.9 to the registrant’s annual report on Form 10-KSB filed April 15, 1999 (the “1998 Form 10-KSB”))
3.4
Articles of Amendment to the Charter dated October 30, 1998 (Incorporated by reference to Exhibit 3.10 to the 1998 Form 10-KSB)
3.5
Articles of Amendment to the Charter filed March 17, 2000 (Incorporated by reference to Exhibit 3.11 to the registrant’s annual report on Form 10-KSB filed April 14, 2000 (the “1999 Form 10-KSB”))
3.6
By-laws (Incorporated by reference to Exhibit 3.2 to the Form 10-SB)
3.7
Amendment and Restated By-laws dated May 19, 2005 (Incorporated by reference to the registrant’s annual report on Form 10-K for the year ended December 31, 2005)
4.1
Form of Rights Certificate Incorporated by reference to registrant’s statement on Form S-1 filed February 13, 2004 Registration File No. 333-109784 (the “Form S-1")
10.1
Natural Gas Sales Agreement dated November 18, 1999 between Tengasco, Inc. and Eastman Chemical Company (Incorporated by reference to Exhibit 10.10 to the registrant’s current report on Form 8-K filed November 23, 1999)
10.2
Amendment Agreement between Eastman Chemical Company and Tengasco, Inc. dated March 27, 2000 (Incorporated by reference to Exhibit 10.14 to the registrant’s 1999 Form 10-KSB)
10.3
Natural Gas Sales Agreement between Tengasco, Inc. and BAE SYSTEMS Ordnance Systems Inc. dated March 30, 2001 (Incorporated by reference to Exhibit 10.20 to the 2000 Form 10-KSB)
10.4
Tengasco, Inc. Incentive Stock Plan (Incorporated by reference to Exhibit 4.1 to the registrant’s registration statement on Form S-8 filed October 26, 2000)
10.5
Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated May 18, 2004 in the principal amount of $2,500,000 (Incorporated by reference to Exhibit 10.47 to the registrant’s quarterly report on Form 10-Q filed May 20, 2004)
10.6
Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated December 30, 2004 in the principal amount of $550,000 (Incorporated by reference from to Exhibit 10.19 to the registrant’s Annual Report on Form 10-K filed March 31, 2005)
10.7
Asset Purchase Agreement dated March 4, 2005 between Tengasco, Inc. and Bear Petroleum, Inc. (Incorporated by reference to Exhibit 10.1 the registrant’s current report on Form 8-K dated March 9, 2005 (the “March 9, 2005 Form 8-K”)
10.8
Assignment and Bill of Sale between Tengasco, Inc. and Bear Petroleum, Inc. (Incorporated by reference to Exhibit 10.2 to the March 9, 2005 Form 8-K)
10.9
Amended and Restated Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated May 19, 2005 in the principal amount of $700,000 ((Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated May 23, 2005)
10.10
Amendment to the Tengasco, Inc. Stock Incentive Plan dated May 19, 2005 (Incorporated by reference to Exhibit 4.2 to the registrant’s registration statement on Form S-8 filed June 3, 2005)
10.11
Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation to Dolphin Offshore Partners, LP dated August 22, 2005 in the principal amount of $1,814,000 (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated August 22, 2005 (the “August 22, 2005 8-K”))
10.12
Amended and Restated Promissory Note made by Tengasco, Inc. and Tengasco Pipeline Corporation dated August 18, 2005 in the principal amount of $700,000 (Incorporated by reference to Exhibit 10.2 to the August 22, 2005 8-K.)
10.13
Subscription Agreement of Hoactzin Partners, L.P. for a 94.275% working interest in the Company’s twelve well drilling program on its Kansas Properties. (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated October 5, 2005)
10.14
Loan and Security Agreement dated as of June 29, 2006 between Tengasco, Inc. and Citibank Texas, N.A. (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated June 29, 2006)
10.15*
Subscription Agreement of Hoactzin Partners, L.P. for the Company’s ten well drilling program on its Kansas Properties dated August 3, 2007.
10.16*
Agreement and Conveyance of Net Profits Interest dated September 17, 2007 between Manufactured Methane Corporation as Grantor and Hoactzin Partners, LP as Grantee.
10.17*
Agreement for Conditional Option for Exchange of Net Profits Interest for Convertible Preferred Stock dated September 17, 2007 between Tengasco, Inc., as Grantor and Hoactzin Partners, L.P., as Grantee.
10.18*
Assignment of Notes and Liens Dated December 17, 2007 between Citibank, N.A., as Assignor, Sovereign Bank, as Assignee and Tengasco, Inc., Tengasco Land & Mineral Corporation and Tengasco Pipeline Corporation as Debtors
10.19
Employment Agreement dated December 18, 2007 between Tengasco, Inc. and Charles Patrick McInturff (Incorporated by reference to Exhibit 10.1 to the registrant’s current report on Form 8-K dated December 18, 2007)
10.20*
Management Agreement dated December 18, 2007 between Tengasco, Inc. and Hoactzin Partners, L.P.
Code of Ethics (Incorporated by reference to Exhibit 14 to the registrant’s annual report on Form 10-K filed March 30, 2004)
17.1
Letter of resignation of Clarke H. Bailey as a Director of the Company dated March 27, 2007 (Incorporated by reference to Exhibit 17.1 to the registrant’s current report on Form 8-K dated March 27, 2007)
21*
List of subsidiaries
23.1*
Consent of LaRoche Petroleum Consultants, Ltd.
31.1*
Certification of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a)
31.2*
Certification of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a)
32.1*
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2*
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
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 31, 2008
Pursuant to the requirements of the Securities and Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in their capacities and on the dates indicated.
Signature
Title
Date
s/Jeffrey R. Bailey
Jeffrey R. Bailey
Director;
Chief Executive Officer
March 31 , 2008
s/Matthew K. Behrent
Matthew K. Behrent
Director
March 31, 2008
s/John A. Clendening
John A. Clendening
Director
March 31, 2008
s/Carlos P. Salas
Carlos P. Salas
Director
March 31, 2008
s/Peter E. Salas
Peter E. Salas
Director
March 31, 2008
s/Mark A. Ruth
Mark A. Ruth
Principal and Financial
Accounting Officer
March 31, 2008
Consolidated Financial Statements
Years Ended December 31, 2007, 2006 and 2005
Report of Independent Registered Public Accounting Firm
Consolidated Financial Statements
Consolidated Balance Sheets
-
Consolidated Income Statements
Consolidated Statements of Stockholders’ Equity
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
-
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and Stockholders
Tengasco, Inc. and Subsidiaries
Knoxville, Tennessee
We have audited the accompanying consolidated balance sheets of Tengasco, Inc. and Subsidiaries as of December 31, 2007 and 2006 and the related consolidated statements of operations, changes in stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2007. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Tengasco, Inc. and Subsidiaries as of December 31, 2007 and 2006 and the results of their operations and cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America.
/s/ Rodefer Moss & Co, PLLC
Knoxville, Tennessee
March 27, 2008
Tengasco, Inc. and Subsidiaries
Consolidated Balance Sheets
December 31,
Assets
Current
Cash and cash equivalents
$ 2,226,839
$ 369,665
Accounts receivable
1,057,148
719,840
Participant receivables
49,872
13,008
Inventory
460,365
550,522
Other current assets
11,056
11,056
Total current assets
3,805,280
1,664,091
Restricted cash
120,500
120,500
Loan fees
223,733
237,738
Oil and gas properties, net (on the basis
of full cost accounting)
13,209,601
12,703,629
Pipeline facilities, net of accumulated
depreciation of $3,423,099 and $2,879,099
12,916,667
13,460,667
Other property and equipment, net
256,058
267,713
Deferred Tax Asset
2,100,000
-
Methane Project
1,649,710
-
$ 34,281,549
$ 28,454,338
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Balance Sheets
December 31,
Liabilities and Stockholders’ Equity
Current liabilities
Current maturities of long term debt
$ 57,887
$ 65,267
Accounts payable
903,238
687,475
Accrued interest payable
10,005
8,432
Other accrued liabilities
360,674
30,410
Total current liabilities
1,331,804
791,584
Asset retirement obligations
531,101
512,015
Long term debt, less currentmaturities
4,315,773
2,730,534
Total liabilities
6,178,678
4,034,133
Stockholders’ equity
Common stock, $.001 par value; authorized 100,000,000 shares;
59,155,750 and 59,003,284 shares issued and outstanding
59,156
59,004
Additional paid-in capital
54,689,525
54,517,333
Accumulated deficit
(26,645,810)
(30,156,132)
Total Stockholders’ equity
28,102,871
24,420,205
$ 34,281,549
$ 28,454,338
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Income Statements
Years ended December 31,
Revenues and other income
Oil and gas revenues
$ 9,300,144
$ 8,896,036
$ 7,076,790
Pipeline transportation revenues
51,492
87,822
94,911
Interest Income
16,988
17,823
1,175
Total revenues and other income
9,368,624
9,001,681
7,172,876
Costs and expenses
Production costs and taxes
4,322,833
3,287,233
3,046,460
Depreciation, depletion and amortization
1,631,468
1,911,416
1,605,043
General and administrative
1,417,001
1,293,109
1,322,616
Interest expense
333,198
168,590
472,655
Public relations
21,605
26,037
30,020
Professional fees
232,197
173,932
263,800
Total costs and expenses
7,958,302
6,860,317
6,740,594
Net Operating Income
1,410,322
2,141,364
432,282
Deferred Tax Benefit
2,100,000
-
-
Gain on Preferred Stock
-
-
655,746
Net Income
$ 3,510,322
$ 2,141,364
$ 1,088,028
Net Income per share
Basic and diluted:
Operations
$ 0.06
$ 0.04
$ 0.02
Total
$ 0.06
$ 0.04
$ 0.02
Shares used in computing earnings per share
Basic
59,117,176
58,851,883
52,019,051
Diluted
60,827,224
60,364,797
52,659,051
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Statements of Stockholders’ Equity
See accompanying Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
(1.)
Summary of Significant Accounting Policies
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, later changed to Onasco Companies, Inc. In 1995, the Company changed its name from Onasco Companies, Inc. to Tengasco, Inc., by merging into Tengasco, Inc., a Tennessee corporation, formed by the Company solely for this purpose.
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. Emphasis is also placed on pipeline and other infrastructure facilities to provide transportation services. The Company utilizes seismic technology to improve the recovery 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 2007, the Kansas Properties produced an average of 14,860 gross barrels of oil per month.
The Company’s activities in 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 2007, the Company produced an average of 347 thousand cubic feet of natural gas per day and 573 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 treatment technologies for the extraction of methane gas from nonconventional sources for delivery through the nation’s existing natural gas pipeline system, including the Company’s TPC pipeline system in Tennessee for eventual sale to natural gas customers.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Basis of Presentation
The accompanying consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America, which contemplate continuation of the Company as a going concern and assume realization of assets and the satisfaction of liabilities in the normal course of business.
The consolidated financial statements include the accounts of the Company, Tengasco Pipeline Corporation, Tennessee Land & Mineral Corporation and Manufactured Methane Corporation. All intercompany balances and transactions have been eliminated.
Use of Estimates
The accompanying consolidated financial statements are prepared in conformity with accounting principles generally accepted in the United States of America which require management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The actual results could differ from those estimates.
Revenue Recognition
The Company uses the sales method of accounting for natural gas and oil revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. Natural gas meters are placed at the customers’ locations and usage is billed monthly.
Cash and Cash Equivalents
The Company considers all investments with a maturity of three months or less when purchased to be cash equivalents.
Inventory
Inventory consists of crude oil in tanks and is carried at lower of cost or market value.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Oil and Gas Properties
The Company follows the full cost method of accounting for oil and gas property acquisition, exploration, and development activities. Under this method, all productive and nonproductive 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, delay rentals and the costs of drilling, completing, equipping and plugging oil and gas wells. 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 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 Company currently has $3,110,768 in unevaluated properties as of December 31, 2007. 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 has determined its reserves based upon reserve reports provided by Ryder Scott Company, Petroleum Consultants in 2005 , and by LaRoche Petroleum Consultants Ltd. in 2006 and 2007.
The capitalized oil and gas properties, 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. The Company has adopted an SEC accepted method of calculating the full cost ceiling test whereby the liability recognized under Statement of Financial Accounting Standard No. 143 (“SFAS”) “Accounting for Asset Retirement Obligation” (“SFAS 143”) is netted against property cost and the future abandonment obligations are included in estimated future net cash flows. No ceiling write-downs were recorded in 2007, 2006, or 2005.
Pipeline Facilities
Phase I of the pipeline was completed during 1999. Phase II of the pipeline was completed on March 8, 2001. Both phases of the pipeline were placed into service upon completion of Phase II. The pipeline is being depreciated over its estimated useful life of 30 years beginning at the time it was placed in service.
Other Property and Equipment and Long - Lived Assets
Other property and equipment are carried at cost. The Company provides for depreciation of other property and equipment using the straight-line method over the estimated useful lives of the assets which range from three to seven years. Long-lived assets (other than oil and gas properties) are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
When evidence indicates that operations will not produce sufficient cash flows to cover the carrying amount of the related asset, a permanent impairment is recorded to adjust the asset to fair value. At December 31, 2007, management believes that carrying amounts of all of the Company’s long-lived assets will be fully recovered over the course of the Company’s normal future operations.
Stock-Based Compensation
The Company recorded $100,877 in 2007, $128,197 in 2006 and $84,030 in compensation expense in 2005 upon the Company’s adoption of SFAS 123 (R) in 2005.
Accounts Receivable
Senior management reviews accounts receivable on a monthly basis to determine if any receivables will potentially be uncollectible. Based on the information available to us, the Company believes no allowance for doubtful accounts as of December 31, 2007 and 2006 is necessary. However, actual write-offs may occur.
Income Taxes
The Company accounts for income taxes using the “asset and liability method.” Accordingly, deferred tax liabilities and assets are determined based on the temporary differences between the financial reporting and tax bases of assets and liabilities, using enacted tax rates in effect for the year in which the differences are expected to reverse. Deferred tax assets arise primarily from net operating loss carry-forwards. Management evaluates the likelihood of realization for such assets at year-end providing a valuation allowance for any such amounts not likely to be recovered in future periods. The Company currently has a net operating loss carry forward of 21,100,000.
Financial instruments which potentially subject the Company to concentrations of credit risk consist principally of cash and accounts receivable. At times, such cash in banks is in excess of the FDIC insurance limit.
The Company’s primary business activities include oil and gas sales to several customers in the states of Kansas and Tennessee. The related trade receivables subject the Company to a concentration of credit risk within the oil and gas industry.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company is presently dependent upon a small number of customers for the sale of gas from the Swan Creek Field, principally Eastman Chemical Company and other industrial customers in the Kingsport area with which the Company may enter into gas sales contracts.
The Company has entered into contracts to supply two manufacturers with natural gas from the Swan Creek Field (Tennessee) through the Company’s pipeline. These customers are the Company’s primary customers for natural gas sales. Additionally, the Company sells a majority of its crude oil primarily to two customers, one each in Tennessee and Kansas. Although management believes that customers could be replaced in the ordinary course of business, if the present customers were to discontinue business with the Company, it could have a significant adverse effect on the Company’s projected results of operations.
In 2007, the Company received 91.4 percent of its revenues from Customer A; 4.9 percent of its revenues from Customer B; and 3.7 percent of its revenues from Customer C.
In 2006, the Company received 85.7 percent of its revenues from Customer A; 10.1 percent of its revenues from Customer B.
In 2005, the Company received 74.6 percent of its revenues from Customer A; 18.6 percent of its revenues from Customer B.
In each of the years 2005 through 2007, the identity of the customers indicated above as either A, B or C was the same from year to year, although the percentage of revenues varied from year to year for those customers.
In accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share” (“SFAS 128”), basic income per share is based on 59,117,176, 58,851,883 and 52,019,051 weighted average shares outstanding for the years ended December 31, 2007, December 31, 2006 and December 31, 2005 respectively. Diluted earnings per common share are computed by dividing income available to common shareholders by the weighted average number of shares of common stock outstanding during the period increased to include the number of additional shares of common stock that would have been outstanding if the dilutive potential shares of common stock had been issued. The dilutive effect of outstanding options and warrants is reflected in diluted earnings per share.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The number of dilutive shares outstanding is 1,710,048 for 2007, 1,512,914 for 2006 and 640,000 for 2005. These are related to options and warrants.
Fair Values of Financial Instruments
Fair values of cash and cash equivalents, investments and short-term debt approximate their carrying values due to the short period of time to maturity. Fair values of long-term debt are based on quoted market prices or pricing models using current market rates, which approximate carrying values.
(2.) Recent Accounting Pronouncements
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 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. The adoption of FIN 48 had no impact on our results of operations or financial position. The Company currently has open tax return periods beginning with December 31, 2004 through December 31, 2007.
In September 2006, the Securities and Exchange Commission staff published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The Company adopted SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. It defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurement
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. It clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company continues to evaluate the impact the adoption of this statement could have on its financial condition, results of operations and cash flows.
In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities - as amended (“SFAS 159”). SFAS 159 permits entities to elect to report eligible financial instruments at fair value subject to conditions stated in the pronouncement including adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial reporting by mitigating volatility in earnings related to current reporting requirements. The Company is considering the applicability of SFAS 159 and will determine if adoption is appropriate. The effective date for SFAS 159 is for fiscal years beginning after November 15, 2007.
In October, 2005 the Company accepted an exchange from 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. to fund the Company’s cash exchange to holders of its Series A, B and C Preferred Stock.
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 continuing to produce 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, 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, all well-drilling obligations of the Company under both the Eight Well and Twelve Well Programs with former preferred stockholders as participants have been satisfied.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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. 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.
On September 17, 2007, the Company entered into a drilling program with Hoactzin for ten wells consisting of approximately three wildcat wells and seven developmental wells to be drilled on the Company’s Kansas Properties (the “Program”). Under the terms of the Program, Hoactzin was to pay the Company $400,000 for each well in the Program completed as a producing well and $250,00 per drilled well that was non-productive. The terms of Program also provide that Hoactzin will receive all the working interest in the ten wells in the Program, but will pay an initial fee to the Company of 25% of its working interest revenues net of operating expenses. This is referred to as a management fee but as defined is in the nature of a net profits interest. The fee paid to the Company by Hoactzin will increase to 85% of working interest revenues when net revenues received by Hoactzin reach an agreed payout point of approximately 1.35 times Hoactzin’s purchase price (the “Payout Point”). The Company will account for funds received for interests in the Program as an offset to oil and gas properties.
As of the date of this Report, the Company has drilled all ten wells in the Program. Of the ten wells drilled, nine were completed as oil producers and are currently producing approximately 84 barrels per day in total. Hoactzin paid a total of $3,850,000 for its interest in the Program resulting in the Payout Point being determined as $5,215,595. The amount paid by Hoactzin for its interest in the Program wells exceeded the Company’s actual drilling costs of approximately $2.8 million for the ten wells by more than $1 million.
Although production level of the Program wells will decline with time in accordance with expected decline curves for these types of well, based on the drilling results of the Program wells and the current price of oil, the Program wells are expected to reach the Payout Point in approximately four years solely from the oil revenues from the wells. However, under the terms of its agreement with Hoactzin reaching the Payout Point has been accelerated by Hoactzin agreeing to apply 75% of the net proceeds it receives from the methane extraction project being developed by the Company’s wholly-owned subsidiary, Manufactured Methane Corporation, at the Carter Valley, Tennessee landfill to the Payout Point. (The methane extraction project is discussed in greater detail below.) Those methane project proceeds when applied will result in the Payout Point being achieved sooner than the estimated four year period based solely upon revenues from the Program wells.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
On December 18, 2007, the Company entered into a Management Agreement with Hoactzin. On that same date, the Company also entered into an agreement with Charles Patrick McInturff employing him as a Vice-President of the Company. Pursuant to the Management Agreement with Hoactzin, Mr. McInturff’s duties while he is employed as Vice-President of the Company will include the management on behalf of Hoactzin of its working interests in certain oil and gas properties owned by Hoactzin and located in the onshore Texas Gulf Coast, and offshore Texas and offshore Louisiana. As consideration for the Company entering into the Management Agreement, Hoactzin has agreed that it will be responsible to reimburse the Company for the payment of one-half of Mr. McInturff’s salary, as well as certain other benefits he receives during his employment by the Company. In further consideration for the Company’s agreement to enter into the Management Agreement, Hoactzin has granted to the Company an option to participate in up to a 15% working interest on a dollar for dollar cost basis in any new drilling or work-over activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement. The term of the Management Agreement is the earlier of the date Hoactzin sells its interests in its managed properties or 5 years.
The following table sets forth information concerning the Company’s oil and gas properties:
December 31,
Oil and gas properties, at cost
18,856,487
$ 18,745,834
Unevaluated properties
3,110,768
1,880,811
Accumulation depreciation,
depletion and amortization
(8,757,654)
(7,923,016)
Oil and gas properties, net
13,209,601
$ 12,703,629
During the years ended December 31, 2007, 2006 and 2005 the Company recorded depletion expense of $834,638, $1,144,711 and $902,131 in 2005.
In 1996, the Company began construction of a 65-mile gas pipeline (1) connecting the Swan Creek development project to a gas purchaser and (2) enabling the Company to develop gas transportation business opportunities in the future. Phase I, a 30-mile portion of the pipeline, was completed in 1998. Phase II of the pipeline, the remaining 35 miles, was completed in March 2001. The estimated useful life of the pipeline for depreciation purposes is 30 years. The Company recorded $544,000, $544,000 and $536,000, in depreciation expense related to the pipeline for the years ended December 31, 2007, 2006 and 2005, respectively.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
In January 1997, the Company entered into an agreement with the Tennessee Valley Authority (“TVA”) whereby the TVA allows the Company to bury the pipeline within the TVA’s transmission line rights-of-way. In return for this right, the Company paid $35,000 and agreed to annual payments of approximately $6,200 for 20 years.
This agreement expires in 2017 at which time the parties may renew the agreement for another 20-year term in consideration of similar inflation-adjusted payment terms.
Other property and equipment consisted of the following:
December 31
Depreciable Life
Machinery and equipment
5-7 yrs
$ 830,734
$ 771,767
Vehicles
2-5 yrs
487,176
521,824
Other
5 yrs
63,734
63,734
Total
1,381,644
1,357,325
Less accumulated depreciation
(1,125,586)
(1,089,612)
Other property and equipment - net
$ 256,058
$ 267,713
The Company uses the straight-line method of depreciation ranging from two years to seven years, depending on the asset life.
Long-term debt to unrelated entities consisted of the following:
December 31,
Note payable to a financial institution, with interest payment only until maturity.
(See Notes 15 & 16)
$4,200,000
$ 2,600,000
Installment notes bearing interest at the rate of 5.5% to 8.25% per annum collateralized by vehicles with monthly payments including interest of approximately $10,000 due through 2010.
173,660
195,801
Total long-term debt
4,373,660
2,795,801
Less current maturities
(57,887)
(65,267)
Long-term debt, less current
maturities
4,315,773
$ 2,730,534
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
8.
Commitments and Contingencies
The Company is a party to lawsuits in the ordinary course of its business. The Company does not believe that it is probable that the outcome of any individual action will have a material adverse effect, or that it is likely that adverse outcomes of individually insignificant actions will be significant enough, in number or magnitude, to have in the aggregate a material adverse effect on its financial statements.
In the ordinary course of business the Company has entered into office leases which have remaining term of 6 months. Approximate future minimum lease payments to be made under non-cancelable operating leases in 2008 are $31,673.
Office rent expense for each of the three years ended December 31, 2007, 2006 and 2005 was approximately $63,346, $63,346, and $ 83,332 respectively.
9.
Cumulative Convertible Redeemable
On August 22, 2005 all holders of the Company's Series B and C Cumulative Convertible Preferred Stock (the "Series B and Series C shares"), having a total aggregate value of $5,113,045 consisting of face value, dividends, and interest exchanged all rights under their Series B and C shares for cash or for the Company's common stock. As a result of the exchange, as of August 22, 2005 the Company no longer had any holders of Series B or C preferred stock and no further obligations under any Series B or C shares. Holders of approximately 53.2% of the face value of outstanding Series B and C shares exchanged their preferred shares having an aggregate value of $2,721,140 for cash payments totaling $1,814,184. The Company obtained the funds for this exchange primarily from proceeds of a loan of $1,814,000 from Dolphin. The loan from Dolphin was evidenced by a secured promissory note dated August 22, 2005 bearing 12% interest per annum payable interest only monthly until the principal amount of the note was to become due on December 31, 2005. A second option offered to the Series B and C holders 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. All of the holders, including Dolphin, of the remaining aggregate value of $2,391,905 or 46.8% of the Series B and C shares selected this option. As a result, a total of 9,567,620 shares of the Company's common stock were issued to those holders. 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.
In total, the Company recorded a gain during 2005 from the exchange of Series A, B and C shares for cash and stock of $655,746, the difference between the carrying amount and the cash settlement amount and the stock issued.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company follows the requirements of SFAS 143. Among other things, SFAS 143 requires entities to record a liability and corresponding increase in long-lived assets for the present value of material obligations associated with the retirement of tangible long-lived assets. Over the passage of time, accretion of the liability is recognized as an operating expense and the capitalized cost is depleted over the estimated useful life of the related asset. Additionally, SFAS 143 required that upon initial application of these standards, the Company must recognize a cumulative effect of a change in accounting principle corresponding to the accumulated accretion and depletion expense that would have been recognized had this standard been applied at the time the long-lived assets were acquired or constructed. The Company’s asset retirement obligations relate primarily to the plugging, dismantling and removal of wells drilled to date. The Company’s calculation of Asset Retirement Obligation used a credit-adjusted risk free rate of 12%, an estimated useful life of wells ranging from 30-40 years, estimated plugging and abandonment cost range from $5,000 per well to $10,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions.
On March 4, 2005 the Company sold its Kansas gas wells, and consequently the asset and the corresponding liability relating to asset retirement obligations on these wells were extinguished. The asset account was credited for $60,998 and the liability was removed in the amount of $133,397, creating a gain on the extinguishment of future obligations in the amount of $72,399, which was credited to interest expense.
The following is a roll-forward of activity impacting the asset retirement obligation for the year ended December 31, 2007:
Balance, December 31, 2005
$ 566,968
Accretion expense
42,340
Liabilities Settled
(97,293)
Balance, December 31, 2006
$ 512,015
Accretion expense
70,929
Liabilities Settled
(51,843)
Balance, December 31, 2007
$ 531,101
In October 2000, the Company approved a Stock Incentive Plan. The Plan is effective for a ten-year period commencing on October 25, 2000 and ending on October 24, 2010. The aggregate number of shares of Common Stock as to which options and Stock Appreciation Rights may be granted to participants under the plan shall not exceed 3,500,000. Options are not transferable, are exercisable for 3 months after voluntary
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
resignation from the Company, and terminate immediately upon involuntary termination from the Company. The purchase price of shares subject to this plan shall be determined at the time the options are granted, but are not permitted to be less than 85% of the fair market value of such shares on the date of grant. Furthermore, a participant in the Plan may not, immediately prior to the grant of an Incentive Stock Option hereunder, own stock in the Company representing more than ten percent of the total voting power of all classes of stock of the Company unless the per share option price specified by the Board for the Incentive Stock Options granted such a participant is at least 110% of the fair market value of the Company’s stock on the date of grant and such option, by its terms, is not exercisable after the expiration of 5 years from the date such stock option is granted.
Stock option activity in 2007, 2006 and 2005 is summarized below:
The following table summarizes information about stock options outstanding and exercisable at December 31, 2006:
Options Outstanding
Options Exercisable
Weighted Average
Exercise Price
Shares
Weighted Average
Remaining
Contractual
Life (years)
Shares
$ 0.27
2,251,000
2.33
1,357,000
$ 0.58
110,000
3.05
110,000
$ 0.81
80,000
3.93
80,000
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The weighted average fair value per share of options granted during 2006 and 2005 range from $0.15 to $0.32, calculated using the Black-Scholes Option-Pricing model. No options were granted in 2007.
Compensation expense of $84,030 related to stock options was recognized in 2005 and $128,197 in 2006 and 100,877 in 2007.
The fair value of stock options used to compute pro forma net loss and loss per share disclosures is the estimated present value at grant date using the Black-Scholes option-pricing model with the following weighted average assumptions for 2006 and 2005: expected volatility of 60% for 2006, and 2005; a risk free interest rate of 3.67% in 2006 and 2005; and an expected option life of 2.5 years for 2006 and 2005.
The Company has taxable income for the periods ending December 31, 2007, December 31, 2006 and December 31, 2005.
A reconciliation of the statutory U.S. Federal income tax and the income tax provision included in the accompanying consolidated statements of operations is as follows:
December 31,
Statutory rate
34%
34%
34%
Tax (benefit)/expense
at statutory rate
1,193,000
$ 728,000
$ 370,000
State income
tax (benefit)/expense
140,000
85,000
43,000
Other
3,000
3,000
3,000
Non-deductible interest
-
Increase/(decreases)in deferred tax asset valuation allowance
(3,436,000)
(816,000)
(416,000)
Total income tax provision (benefit)
(2,100,000)
-
-
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
The Company’s deferred tax assets and liabilities are as follows:
December 31
Deferred tax assets:
Net operating loss carryforward
$7,314,000
$ 8,700,000
$ 9,616,000
Capital loss carry forward
263,000
263,000
263,000
Total deferred tax assets
7,577,000
8,963,000
9,879,000
Deferred tax liability:
Basis difference in pipeline
250,000
300,000
400,000
Total deferred liability
250,000
300,000
400,000
Total net deferred taxes
7,327,000
8,663,000
9,479,000
Valuation allowance
(5,227,000)
(8,663,000)
(9,479,000)
Net deferred tax asset
$2,100,000
-
-
As of December 31, 2007, Management, using the “more likely than not” criteria for recognition, elected to recognize a deferred tax asset of $2.1 million. The recognition of the deferred tax asset in 2007 relates to net operating loss carryforwards and will provide a better matching of income tax expense with taxable income in future periods. The current provision reflects the recognition of $1,336,000 current income tax benefit (fully offset by the current provision related to 2007 taxable income) and $2,100,000 in benefit relating to future periods.
No income tax expense was recognized for the years ended December 31, 2006 or December 31, 2005 because deferred tax benefits, derived from the Company’s prior net operating losses, were previously fully reserved and were being offset against tax liabilities that would otherwise arise from the results of current operations. Management continuously estimates the realization of the Company’s deferred tax assets based on its anticipation of the likely timing and adequacy of future net income, after taking into consideration the increased uncertainty attributed to a lengthening horizon before the projected realization of future deferred assets.
As of December 31, 2007, the Company had net operating loss carry-forwards of approximately $21,100,000 which will expire between 2011 and 2023 if not utilized.
The Company paid approximately $262,268, $126,250, and $524,000, for interest in 2007, 2006 and 2005, respectively. No interest was capitalized in 2007, 2006 or 2005. No income taxes were paid in 2007, 2006, or 2005.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
On May 10, 2004 the Court entered its final order approving the fairness of the settlement to the class, dismissing the action pursuant to a Settlement Stipulation, and fully releasing the claims of the class members in Paul Miller v. M. E. Ratliff and Tengasco, Inc., No. 3:02-CV-644 in the United States District Court for the Eastern District of Tennessee, Knoxville, Tennessee. This action sought certification of a class action to recover on behalf of a class of all persons who purchased shares of the Company’s common stock between August 1, 2001 and April 23, 2002, unspecified damages allegedly caused by violations of the federal securities laws. In January, 2004 all parties reached a settlement subject to court approval. The Court entered its order approving the settlement on May 10, 2004. Under the settlement, the Company paid into a settlement fund the amount of $37,500 to include all costs of administration, contributed 150,000 shares of stock of Miller Petroleum, Inc. owned by the Company and issued 300,000 warrants to purchase a share of the Company’s common stock for a period of three years from date of issue at $1 per share subject to adjustments. The Rights Offering adjusted this price to $0.45 per share. These Warrants expire on September 12, 2008. The Miller Petroleum, Inc. investment had a net carrying value of $60,000 and a cumulative other comprehensive loss of $90,000, which was reversed from cumulative other comprehensive loss and recognized as a realized loss during the third quarter of 2004.
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 an initial 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. The facility has standard loan covenants such as current ratios, interest coverage ratios etc, with which the Company is in compliance.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
$1.393 million of the $2.6 million loan proceeds were used by the Company on June 29, 2006 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 12-well Kansas drilling program for Hoactzin. The Company incurred loan closing costs consisting of legal fees, mortgage taxes, commissions and bank fees totaling $285,224. This amount will be amortized over the term of the note and its successor (See Note 16).
On April 19, 2007 the Company borrowed an additional sum of $700,000 from Citibank, N.A. under its existing revolving credit facility dated June 29, 2006. The additional borrowing resulted from an increase in the Company’s borrowing base under the Citibank credit facility from $2.6 million to $3.3 million based upon Citibank’s periodic review of the Company’s borrowing base. With the additional borrowing, the Company has borrowed the full amount of its $3.3 million borrowing base under the revolving Citibank credit facility. Repayment of this additional sum is subject to the terms and conditions of the Citibank credit facility. The additional amount borrowed will be used for further development of the Company’s producing properties.
On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by the Company.
Under the facility as assigned to Sovereign, 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 $20 million or the Company’s borrowing base in effect from time to time. The Company’s initial borrowing base with Sovereign was set at $7.0 million, an increase from its borrowing base of $3.3 million with Citibank prior to the assignment.
The Company’s initial borrowing on December 17, 2007 under its new facility with Sovereign was approximately $4.2 million which will bear interest at a floating rate equal to prime as published in the Wall Street Journal plus 0.25% resulting in a current interest rate of approximately 7.5%. Interest only is payable during the term of the loan and the principal balance of the loan is due December 31, 2010. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane Project assets.
The Company used a portion of the $4.2 million borrowed from Sovereign to pay off the funds it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign was used to pay bank fees and attorney fees relating to the assignment in the amount of approximately $75,000 and the balance of approximately $825,000 was used to pay a portion of the purchase price for equipment to be utilized in the Methane Project currently under construction in Carter Valley, Tennessee by MCC, the Company’s wholly-owned subsidiary.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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 was thereafter assigned to the Company’s wholly-owned subsidiary, Manufactured Methane Corporation (“MMC”) and provides that MMC will purchase all the naturally produced gas stream presently being collected and flared at the municipal solid waste landfill in Carter Valley 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 (the “Methane Project”).
MCC has placed equipment orders for its first stage of process equipment (cleanup and carbon dioxide removal) and the second stage of process equipment (nitrogen rejection) for the Methane Project. It is anticipated that the total costs for the Project including pipeline construction, will be approximately $4.1 million including costs for compression and interstage controls. The costs of the Methane Project to date have been funded primarily by (a) the money received by the Company from Hoactzin to purchase its interest in the Ten Well Program which exceeded the Company’s actual costs of drilling the wells in that Program by more than $1 million (b) cash flow from the Company’s operations in the amount of approximately $1 million and (c) $825,000 of the funds the Company borrowed from its credit facility with Sovereign Bank. The Company anticipates that most of the remaining balance of the Methane Project costs will be paid from the Company’s cash flow.
The Company anticipates that the equipment ordered by MMC will be manufactured and delivered to allow operations to begin in mid-2008 after equipment installation, testing, and startup procedures are begun. Commercial deliveries of gas will begin when the equipment is installed and tested and the pipeline is constructed. Upon commencement of operations, the methane gas produced by the project facilities will be mixed in the Company’s pipeline and delivered and sold to Eastman Chemical Company (“Eastman”) under the terms of the Company’s existing natural gas purchase and sale agreement. 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 substantially increase the current volumes of natural gas being delivered to Eastman by the Company from its Swan Creek field. At an assumed sales price of gas of $7 per MMBtu, near the average natural gas price received by the Company in 2007, the anticipated net revenues to the Company would be approximately $800,000 per year from the Methane Project based on anticipated volumes and expenses. The gas supply from this project is projected to grow over the years as the underlying operating
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
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.
As part of the Methane Project agreement, the Company agreed to install a new force-main water drainage line for Allied Waste Industries, an affiliate of BFI, the landfill owner, in the same two-mile pipeline trench as the gas pipeline needed for the project, reducing overall costs and avoiding environmental effects to private landowners resulting from multiple installations of pipeline. Allied Waste will pay the additional costs for including the water line. Construction of the gas pipeline needed to connect the facility with the Company’s existing natural gas pipeline began in January 2008. As a certificated utility, the Company’s pipeline subsidiary, TPC, requires no additional permits for the gas pipeline construction. The Company currently anticipates that pipeline construction will be concluded approximately the same time as equipment deliveries and installations occur or in the May to June 2008 time period, subject to weather delays during wintertime construction.
On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program, pursuant to a separate agreement with the Company was conveyed a 75% net profits interest in the Methane Project. When the Methane Project comes online, the revenues from the Project received by Hoactzin will be applied towards the determination of the Payout Point (as defined above) for the Ten Well Program. When the Payout Point is reached from either the revenues from the wells drilled in the Program or the Methane Project or a combination thereof, Hoactzin’s net profits interest in the Methane Project will decrease to a 7.5% net profits interest. The Company believes that the application of revenues from the methane project to reach the Payout Point will rapidly accelerate reaching the Payout Point. Those excess funds provided by Hoactzin were used to pay for approximately $1,000,000 of equipment required for the Methane Project, or about 25% of the Project’s capital costs. The availability of the funds provided by Hoactzin eliminated the need for the Company to borrow those funds, to have to pay interest to any lending institution making such loans or to dedicate Company revenues or revenues from the Methane Project to pay such debt service. Accordingly, the grant of a 7.5% interest in the Methane Project to Hoactzin was negotiated by the Company as a favorable provision to the Company in the overall transaction.
As security required by Tennessee oil and gas regulations, the Company placed $120,500 in a Certificate of Deposit to cover future asset retirement obligations for the Company’s Tennessee wells.
The following table sets forth for the fiscal periods indicated, selected consolidated financial data.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Fiscal Year Ended 2007
First Quarter
Second Quarter
Third Quarter(a)
Fourth Quarter(a)
Revenues
$1,772,400
$2,220,439
$2,375,229
$3,000,556
Net loss/income
($209,165)
$ 330,756
$1,580,662
$1,808,069
Net loss/income attributable to common stockholders
($209,165)
$330,756
$1,580,662
$1,808,069
Income/loss per common share
$ 0.00
$ .01
$ 0.03
$ 0.03
Fiscal Year Ended 2006
First Quarter
Second Quarter
Third Quarter
Fourth Quarter
Revenues
$ 2,098,969
$ 2,354,736
$ 2,251,274
$ 2,296,702
Net loss/income
316,347
720,769
519,094
585,154
Net loss/income attributable to common stockholders
$ 316,347
$ 720,769
$ 519,094
$ 585,154
Income/loss per common share
$ 0.01
$ 0.01
$
0.01
$
0.01
(a)
The company recorded 1.1 million in deferred tax asset in the third quarter of 2007 and 1.0 million in the fourth quarter of 2007.
20. Supplemental Oil and Gas Information (unaudited)
Information with respect to the Company’s oil and gas producing activities is presented in the following tables. Estimates of reserve quantities, as well as future production and discounted cash flows before income taxes, were determined by Ryder Scott Company, L.P. as of December 31, 2005, The reserves were estimated by LaRoche Petroleum Consultants Ltd. in 2006 and 2007.
Oil and Gas Related Costs
The following table sets forth information concerning costs related to the Company’s oil and gas property acquisition, exploration and development activities in the United States during the years ended:
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Property acquisitions
Proved
200,000
Unproved
-
Less -proceeds from
Sales of properties
-
-
$ (2,651,770)
Development Cost
4,990,611
4,172,462
402,876
5,190,611
$ 4,172,462
$ (2,248,894)
Results of Operations from Oil and Gas Producing Activities
The following table sets forth the Company’s results of operations from oil and gas producing activities for the years ended:December 31,
Revenues
9,300,144
$ 8,896,036
$ 7,076,790
Production costs and taxes
(4,160,488)
(3,145,244)
(2,956,307)
Depreciation, depletion and amortization
(834,638)
(1,144,711)
(902,132)
Income from oil and gas producing activities
4,305,018
$ 4,606,081
$ 3,218,351
In the presentation above, no deduction has been made for indirect costs such as corporate overhead or interest expense. No income taxes are reflected above due to the Company’s operating tax loss carry-forwards.
Oil and Gas Reserves
The following table sets forth the Company’s net proved oil and gas reserves at December 31, 2007, 2006 and 2005 and the changes in net proved oil and gas reserves for the years then ended. Proved reserves represent the quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be recoverable in the future years from known reservoirs under existing economic and operating conditions. Reserves are measured in barrels (bbls) in the case of oil, and units of one thousand cubic feet (Mcf) in the case of gas.
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows from the Company’s proved oil and gas reserves is presented in the following two tables:
Tengasco, Inc. and Subsidiaries
Notes to Consolidated Financial Statements
Estimated future net cash flows represent an estimate of future net revenues from the production of proved reserves using current sales prices, along with estimates of the operating costs, production taxes and future development and abandonment costs (less salvage value) necessary to produce such reserves. The average prices used at December 31, 2007, 2006, and 2005 were $85.44, $56.50, and $55.81, per barrel of oil and $7.21, $8.33 and $11.31 per MCF of gas, respectively. No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
Operating costs and production taxes are estimated based on current costs with respect to producing properties. Future development costs are based on the best estimate of such costs assuming current economic and operating conditions.
Income tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production and development costs over the current tax basis of the properties involved, less applicable net operating loss carry-forwards, for both regular and alternative minimum tax. For the years ended December 31, 2007, 2006 and 2005 the Company’s available net operating loss carry forwards offset all tax effects applicable to the discounted future net cash flows.
The future net revenue information assumes no escalation of costs or prices, except for gas sales made under terms of contracts which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly, revisions in the future could be significant.