TGC

Tengasco, Inc

Tengasco is in the business of exploring for and producing oil and natural gas in Kansas and Tennessee.

The Company leases producing and non-producing properties with a view toward exploration and development and owns pipeline and other infrastructure facilities used to provide transportation services. The Company utilizes seismic technology to improve the discovery of reserves.

The Company’s primary area of production and development is in Kansas. The Company’s activities in Kansas commenced in 1998 when it acquired approximately 32,000 acres of leases and production in the vicinity of Hays, Kansas (the “Kansas Properties”). During 2008, the Kansas Properties produced an average of 19,623 barrels of oil per month.

The Company’s oil and gas leases in Tennessee are located in Hancock, Claiborne, and Jackson counties. The Company has drilled primarily on a portion of its leases known as the Swan Creek Field in Hancock County focused within what is known as the Knox Formation, one of the geologic formations in that field. During 2008, the Company sold an average of 215 thousand cubic feet of natural gas per day and 533 barrels of oil per month from 19 producing gas wells and 4 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’s wholly-owned subsidiary, Manufactured Methane Corporation, is engaged in developing and operating treatment and delivery facilities using the latest developments in available technologies for the extraction of methane gas from non-conventional sources for delivery through the nation’s existing natural gas pipeline system, including the Company’s TPC pipeline system in Tennessee for eventual sale to natural gas customers.

The Company also has a management agreement with Hoactzin Partners, L.P. (“Hoactzin”) to manage Hoactzin’s oil and gas properties in the Gulf of Mexico offshore Texas and Louisiana. As consideration for that agreement the Company obtained reimbursement from Hoactzin of a portion of salary and expenses for the Company’s Vice President Patrick McInturff, as well as an option to participate in production and exploration activities in Hoactzin’s properties in those areas. 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.

General

1. The Kansas Properties

The Company’s Kansas Properties presently include 184 producing oil wells in the vicinity of Hays, Kansas. The Company employs a full time geologist in Kansas to oversee acquisition of new properties, and exploration and exploitation of Kansas Drilling prospects on both newly acquired acreage and existing leases for development. The Company employs a full time production manager to oversee the daily function of all producing wells and to implement the work-over programs employed by the Company to boost production from older wells.

On July 2, 2008, the Company acquired 19 leases encompassing approximately 1,577 acres and 41 producing wells producing approximately 80 barrels of oil per day in Rooks County, Kansas together with salt water disposal wells and related equipment from Black Diamond Oil, Inc. for $5.35 million. The leases acquired are in the Company’s core area in Kansas and comprise what is known as the Riffe Field that had been owned and operated by Black Diamond for many years. The Riffe Field production that was purchased has yielded immediate benefits to the Company’s oil production. The Company has completed several polymer treatments on existing Riffe Field wells that has resulted in increasing production by the end of December 2008 to 147 barrels of oil per day. Total production from the acquired wells during the six month period the Company owned them in 2008 was 21,995 barrels of oil, an average of 122 barrels per day.

In addition to the Riffe Field acquisition, in 2008, the Company continued to focus its exploration and drilling activities in Kansas. In 2008, the Company drilled twelve gross new wells on its Kansas Properties, one of which was the last well drilled in the Company’s ten-well program discussed below in greater detail. Of these new wells, nine are producing commercial quantities of oil, including a wildcat well, the Albers #1 in Trego County, Kansas. These new wells are producing approximately 84 barrels of oil per day. The Company also continued in 2008 its program of work-overs of existing wells to increase production. The Company’s continued focus on its Kansas oil production and the results achieved by the Company from the Riffe Field acquisition and the Company’s ongoing operations, drilling and work-overs have had a positive impact on increasing the Company’s oil production.

The Riffe Field acquisition also continued in 2008 the Company’s lease acquisition program in Kansas to acquire oil and gas leases in areas near its previous lease holdings where the Company believes there is a likelihood of additional oil production. The Company continued to collect and analyze substantial seismic data to aid it in its drilling operations. While the Company intends in 2009 to continue to acquire strategic leases in the area of its existing wells, the decline in oil prices may have an adverse impact on those plans. Any prolonged decrease in oil prices will have a chilling effect on the Company’s plans and abilities to acquire new leases since the acquisition of such properties may not be commercially reasonable at lower oil prices.

A.

Kansas Drilling Programs

1. The Ten 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 $250,000 per drilled well that was non-productive.

The terms of the 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”).

In March 2008, the Company drilled and completed the tenth and final well in the Program as a producing well. Of the ten wells drilled, nine were completed as oil producers and are currently producing approximately 106 barrels per day in total. Hoactzin paid a total of $3,850,000 (the “Purchase Price”) for its interest in the Program resulting in the Payout Point being determined as $5,215,595. The Purchase Price paid by Hoactzin for its interest in the Program wells exceeded the Company’s actual drilling costs of approximately $2.6 million for the ten wells by more than $1 million.

In 2008, the wells from the Program produced 35,827 barrels of oil of which 21,500 were net to Hoactzin. As of December 31, 2008, net revenues received by Hoactzin from the Program total $1,899,835 which leaves a balance of $3,315,759 until the Payout Point is reached.

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 could be accelerated by the application of 75% of the net proceeds Hoactzin receives from the methane extraction project being developed by the Company’s wholly-owned subsidiary, Manufactured Methane Corporation, at the Carter Valley, Tennessee landfill (the “Methane Project”) toward reaching the Payout Point. (The Methane Project is discussed in greater detail below.) The 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.

On September 17, 2007, the Company entered into an additional agreement with Hoactzin providing that if the Ten Well Program and the Methane Project interest in combination failed to return net revenues to Hoactzin equal to 25% of the Purchase Price it paid for its interest in the Ten Well Program by December 31, 2009, then Hoactzin had an option to exchange up to 20% of its net profits interest in the Methane Project for convertible preferred stock to be issued by the Company with a liquidation value equal to 20% of the Purchase Price less the net proceeds received at the time of any exchange. The conversion option would be set at issuance of the preferred stock at the then twenty business day trailing average closing price of Company stock on the American Stock Exchange. This option can not occur at year-end 2009 because approximately 50% of the Purchase Price was returned to Hoactzin from revenues from the wells in the Program by the end of 2008.

Hoactzin has a similar option each year after 2010 in which Hoactzin’s then-unrecovered Purchase Price at the beginning of the year is not reduced 20% further by the end of that year, using the same conversion option calculation. The Company, however, may in any year make a cash payment from any source in the amount required to prevent such an exchange option for preferred stock from arising. In addition, the conversion right is limited to a conversion of no more than 19% in the aggregate of the outstanding common shares of the Company. In the event Hoactzin’s 75% net profits interest in the Methane Project were fully exchanged for preferred stock Hoactzin would retain no net profits interest in the Methane Project after the full exchange.

Under this exchange agreement, if no proceeds at all were received by Hoactzin through 2009 or in a later year (i.e. a worst-case scenario already impossible in view of the success of the Program), then Hoactzin would have an option to exchange 20% of its interest in the Methane Project beginning in 2011 and each year thereafter for preferred stock convertible at the trailing average price before each year’s issuance of the preferred. The number of common shares into which the preferred stock could be converted cannot be currently calculated. because the conversion price is based on a future stock price.

However, as stated, as of December 31, 2008, net revenues received by Hoactzin from the wells in the Program in 2008 totaled $1,899,835 leaving a balance of $1,950,195 to the point at which no preferred stock can be issued to Hoactzin under the Program, thus making it highly unlikely that any preferred stock will ever be issued to Hoactzin. The Company notes that with the demonstrated successful results of production from the wells in the Program that the payout of 25% of the Purchase Price was reached by year-end 2008, a full year before the December 31, 2009 date and no requirement to issue preferred stock will arise in 2010. The Company further anticipates that at current prices of about $40 per barrel of oil and $5.00 per MCF of gas, and at currently expected sales levels of methane gas from the Methane Project to come online in 2009, that the balance of the unrecovered Purchase Price by Hoactzin will be fully recovered by Hoactzin by year-end 2010. As a result, the Company believes it is highly unlikely that any obligation to issue preferred stock will arise under the terms of this agreement at any time in the future.

2. The Eight Well Program

An eight-well drilling program in Kansas (the “Eight Well Program”) was offered to the holders of the Company’s Series A 8% Cumulative Convertible Preferred Stock (“Series A Shares”) in 2006 in exchange for their Series A Shares. This resulted in the participants acquiring approximately an 81% working interest in the eight wells and the Company retaining the remaining 19% working interest. Under the terms of the Eight Well Program, the former Series A shareholders participating in the Eight Well Program were to receive all of the cash flow from their 81% working interest in the eight wells until they recovered 80% of the face value of the Series A Shares they exchanged for their interests in the Eight Well Program. At that point, for the rest of the productive lives of those eight wells, the Company will receive 85% of the cash flow from the 81% working interest in those wells as a management fee and the Series A shareholders will receive the remaining 15% of the cash flow.

All of the wells in the Eight Well Program have been drilled and have produced sufficient revenues to the participants so that the management fee to the Company became effective in 2007. This had the effect of increasing the Company’s net interest in the Program Wells from approximately 19% to an effective 88% interest and resulting in approximately an additional $50,000 in revenues per month at 2007 oil prices to the Company’s interest in those wells. In 2008, the Eight Well Program produced 17,510 gross barrels of oil of which 15,321 barrels were net to the Company.

3. The Twelve (Six) Well Program

In 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.

The Company drilled six of the wells in the Twelve Well Program. All but one of those wells is continuing to produce commercial quantities of oil. On June 29, 2006 the Company borrowed $2,600,000 pursuant to its credit facility with Citibank Texas, N.A. and used $1.393 million of the loan proceeds to exercise its option to repurchase from Hoactzin, its 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. 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 receives 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. These overriding royalties were part of the terms agreed upon at the inception of the Twelve Well Program if the repurchase option were exercised.

In 2008, the six wells of the converted Twelve Well Program produced 8,963 barrels of oil of which 6,013 barrels were net to the Company.

The Company has completed all of its drilling obligations under the Eight Well and Twelve Well Programs the Company entered into to facilitate the buy-out of its Series A, B and C former preferred stockholders. In addition, revenues from these Program Wells have been sufficient so that in April 2008, the Twelve Well Program joined the Eight Well Program in reaching the reversionary “payout point” at which the Company starts to receive a management fee equal to 85% of the cash flow from the participants’ working interest from the six wells in the Twelve Well Program. That management fee together with the Company’s original working interest results in increasing the Company’s net effective working interest in the wells of both the Eight and Twelve Well Programs from 19% to 88%.

B.

Kansas Production

The Company’s gross oil production in Kansas increased in 2008 from 2007 by 30%. In 2008, the Company produced 231,598 barrels of oil in Kansas compared to 178,311 in 2007. In 2008, the wells in the Eight Well Program produced 17,513 gross barrels of oil; the wells in the Twelve Well Program (now converted to a six well program) produced 8,963 gross barrels; the wells in the Ten Well Program produced 35,827 gross barrels of oil; wells that were polymered produced 14,309 barrels; and the nine new wells drilled in 2008 in which the Company had a 100% working interest produced 23,051 barrels of oil of which, after landowner’s royalties, 20,170 barrels were net to the Company.

There are also additional capital development projects that the Company is considering to increase current oil production with respect to the Kansas Properties, including recompletion of wells and major work-overs. Previously this development was funded by cash flow from the Company’s operations, which have been negatively impacted by current lower oil prices. These current lower oil prices means that cash flow development will slow dramatically in 2009 from the development levels in 2008. At this time, drilling plans and development of proved undeveloped (“PUD”) wells have been pushed back to the end of 2009 or beyond, depending on future oil prices and the economics of that development. These former PUD wells are not included in the Company’s December 31, 2008 reserve report (see, Item 2, “Properties – Reserve Analysis” of this Report) and the corresponding volumes from those PUD wells also have been removed due to the price effect of the end of the year oil pricing.

2. The Tennessee Properties

In the early 1980’s Amoco Production Company owned approximately 50,500 acres of oil and gas leases in the Eastern Overthrust in the Appalachian Basin, including the area now referred to as the Swan Creek Field. Amoco successfully drilled two natural gas discovery wells in the Swan Creek Field to the Knox Formation. These wells, once completed, had a high pressure and apparent volume of deliverability of natural gas. In the mid-1980’s, however, development of this Field was cost prohibitive due to a substantial decline in worldwide oil and gas prices which was further exacerbated by the high cost of constructing a necessary 23-mile pipeline across three mountain ranges and crossing the environmentally protected Clinch River from Sneedville, Tennessee to deliver gas from the Swan Creek Field to the closest market in Rogersville, Tennessee. In July 1995, the Company acquired the Swan Creek leases and began development of the field.

A. Swan Creek Pipeline Facilities

The Company’s completed pipeline system which is owned and operated by Tengasco Pipeline Corporation (“TGC”), the Company’s wholly-owned subsidiary, extends 65 miles from the Swan Creek Field to a meter station at Eastman Chemical Company’s (“Eastman”) plant in Kingsport, Tennessee.

Eastman is the primary customer of the gas produced from the Company’s Swan Creek Field. The pipeline system was built for a total cost of $16,329,552.

B. Swan Creek Production and Development

The Company has concluded based on the results of drilling and testing two infield development wells in 2004 together with the accumulation of data from previously drilled wells and seismic data that drilling new gas wells in the Swan Creek Field would not achieve any significant increase in daily gas production totals from the Field; the current wells in production in the Swan Creek Field would be capable of and would likely produce all the remaining reserves in that Field; and, that only limited additional gas reserves could be added with additional infield developmental drilling. As a result, the Company has not drilled any new gas wells in the Swan Creek Field in over four years.

Because no drilling for natural gas directly in Swan Creek is anticipated in the future, the current production levels less decline are the sole value of natural gas reserves and production. The existing production and the current 19 wells producing natural gas are showing typical Appalachian production declines, which exhibit a long-lived nature but more modest volumes. The experienced decline in actual production levels from existing wells in the Swan Creek Field from 2007 to 2008 was expected and predictable. Although there can be no assurance, the Company expects these natural rates of decline in the future will be comparable to the decline experienced over the 2007-2008 period, and that ongoing production from existing wells will tend to stabilize near current production levels. Variations in year-end natural gas prices and lack of interest to invest in Swan Creek in the foreseeable future have resulted in an adjustment to the reserve volumes to reflect only the reserves associated with currently producing wells. The Company maintains an interest and anticipates drilling additional oil prospects in Swan Creek. It also has an interest in seeking other exploration targets in Tennessee outside of Swan Creek but near the Company’s pipeline, with other industry partners.

The deliverability of natural gas from the Swan Creek Field will not be sufficient to satisfy the volumes deliverable under its contracts with Eastman and BAE in Kingsport, Tennessee. The Eastman contract provides that Eastman will buy a minimum of the lesser of eighty percent of that customer’s daily usage or 10,000 MMBtu per day, and the BAE contract provides that BAE will buy a minimum of all of that customer’s usage or 5,000 MMbtu per day after Eastman’s volumes have been provided. In 2008, the Company’s volume sold from the field was approximately 215 MMBtu per day. The Company’s contracts with these customers are for natural gas produced from the Swan Creek Field. So long as that field is not capable of supplying these volumes of natural gas, the Company is not in breach or violation of these contracts. No penalty is associated with the inability of the Field to produce the volumes that the Company could deliver and buyers would be obligated to buy under their industrial contracts if the volumes were physically available from the Field. However, in the event that the Company was found to be in breach of its obligations for failure to deliver any volumes of gas that is produced from the Swan Creek Field to either of these customers, the agreements limit potential exposure to damages.

Damages are limited to no more than $.40 per MMBtu for any replacement volumes that are proved in a court proceeding as having been obtained to replace volumes required to be furnished but not furnished by the Company.

During 2008, the Company had 19 producing gas wells and 4 producing oil wells in the Swan Creek Field. Gas sales from the Swan Creek Field during 2008 averaged 215 Mcf per day compared to 347 Mcf per day in 2007.

In January 2008, the Company signed a farmout agreement with Jacobs Energy, L.L.C. (“Jacobs Energy”) of Glasgow, Kentucky related to development of the Company’s 1,405 leased acres in Hancock County, Tennessee and an additional area of approximately 20,000 surrounding acres constituting an area of mutual interest (“AMI”) for the purpose of exploring the rim of the Swan Creek anticline for Devonian shale gas production. The agreement is in the form of a “drill to earn” relationship whereby Jacobs Energy must establish commercial production at its sole cost from the first two test wells in order to earn a 50% interest in the two test wells and the right to participate on a fifty-fifty basis in all remaining wells that may be drilled in the AMI. The Company has no obligation for any of the costs of the two test wells. The Company would bear 50% of the costs of any new wells drilled in the future within the AMI. In the event commercial production is not established, Jacobs Energy does not earn any interest in the test wells nor in the AMI and the farmout agreement terminates.

By the end of 2008, Jacobs Energy had re-completed the Ted Hall No. 1 well, which constituted the completion of the first of the two test wells under the farmout agreement. Jacobs Energy plans to drill the required second test well in 2009. Testing of the Ted Hall No. 1 indicates a possible commercial volume of natural gas; however, the preliminary gas analysis of the gas from this well indicates a high nitrogen level exceeding thirty percent which would prevent the gas from being transported by pipeline without treatment for nitrogen removal. The nitrogen content may decrease as the volume of injected nitrogen that was used to fracture the well is recovered in combination with the natural gas testing volumes currently being produced from the well. However, it is also possible that the nitrogen content may not decrease, as some wells producing from the Devonian shale in this general area are subject to having a higher naturally occurring nitrogen content than would be acceptable in the regional pipeline systems, including the Company’s pipeline. Consequently, in order to establish commercial production from this type of well, the nitrogen may need to be physically removed after the gas is produced. Typically, this is performed by installing a treatment plant located at or near the well or wells. An accumulation of many wells is typically required to contribute enough gas production to the treatment plant in order to economically amortize the very significant costs involved in nitrogen removal. Thus, these costs may not be justified in the event significant volumes of gas cannot be physically routed to the treatment plant. The Ted Hall No. 1 well is not currently connected to any pipeline pending the completion and results of the second test well.

When Jacobs Energy drills the second test well (which is expected to occur in 2009) both the volume and gas quality will be considered in determining whether the test wells are capable of commercial production. Under the farmout agreement, the Company has the sole option of determining existence of commercial production from the two test wells.

Depending on the determination of commercial viability, it will be necessary to lay a pipeline extension of about 2.2 miles in order to tie in any production from these wells to the Company’s existing 65-mile Swan Creek pipeline. If the Company determines that the wells are non-commercial, Jacobs Energy may choose to complete the pipeline extension at its own cost, and the Company would credit a portion of any future gas sales proceeds from its 50% interest in the wells, if any sales actually occur, toward repayment for the Company’s 50% of the pipeline costs. The Company is not otherwise obligated in that case for any costs of the two test wells or the pipeline. In addition, if the pipeline extension is constructed by Jacobs Energy at its own cost, the Company would incur no penalty for having not consented to construction of the pipeline by Jacobs Energy. It is important to note, however, that if Jacobs Energy completes the pipeline at its own cost, the Company’s subsidiary, TPC, is not obligated to accept, and cannot accept the gas under its tariffs on file, if the nitrogen content of the gas tendered for pipeline delivery does not change significantly from the levels currently being produced from the first test well. In summary, upon completion of the two test wells, the anticipated future gas prices, the measured gas volumes from the test wells, and the gas quality and any necessary treatment costs will all have a bearing upon the Company’s final determination of whether the project may be capable of producing merchantable natural gas in commercial quantities.

3. The Methane Project

On October 24, 2006 the Company signed a twenty-year Landfill Gas Sale and Purchase Agreement (the “Agreement”) with BFI Waste Systems of Tennessee, LLC (“BFI”), an affiliate of Allied Waste Industries (“Allied”). In 2008 Allied merged into Republic Services, Inc. (“Republic”). The Agreement was 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 Republic in Church Hill, Tennessee. Republic’s facility is located about two miles from the Company’s existing pipeline serving Eastman Chemical Company (“Eastman”). The Company has installed a proprietary combination of advanced gas treatment technology to extract the methane component of the purchased gas stream. Methane is the principal component of natural gas and makes up about half of the purchased gas stream by volume. The Company has constructed a small diameter pipeline to deliver the extracted methane gas to the Company’s existing pipeline for delivery to Eastman (the “Methane Project”).

The total cost for the Methane Project including pipeline construction, was approximately $4.3 million including costs for compression and interstage controls. The costs of the Methane Project were funded primarily by (a) the money received by the Company from Hoactzin to purchase its interest in the Ten Well Program which exceeded the Company’s actual costs of drilling the wells in that Program by more than $1 million, (b) cash flow from the Company’s operations, and (c) $825,000 of the funds the Company borrowed from its credit facility with Sovereign Bank.

Commercial deliveries of gas will begin when the equipment is fully tested and emission permits are obtained. Upon commencement of operations, it is anticipated that the methane gas produced by the project facilities will be mixed in the Company’s pipeline and delivered and sold to Eastman under the terms of the Company’s existing natural gas purchase and sale agreement with Eastman. At current gas production rates and expected extraction efficiencies, when commercial operations of the Project begin, the Company initially estimated it would deliver about 418 MCF 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. The gas supply from this project is projected to grow over the years as the underlying operating landfill continues to expand and generate additional naturally produced gas, and for several years following the closing of the landfill, currently estimated by Republic to occur between the years 2022 and 2026.

As part of the Methane Project agreement, the Company has installed a new force-main water drainage line for Republic, 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. Republic has paid the additional material costs for including the water line of approximately $700,000. Construction of the gas pipeline needed to connect the facility with the Company’s existing natural gas pipeline began in January 2008 and was completed in December 2008. As a certificated utility, the Company’s pipeline subsidiary, TPC, required no additional permits for the gas pipeline construction.

At year-end 2008, MMC was finalizing steps necessary to declare the startup of commercial gas production at the Carter Valley landfill in Church Hill, Tennessee. Initial volumes of methane were produced in late December 2008 and have occurred on an intermittent basis since that time as MMC implemented the startup process. During the first two months of 2009, Eastman was reviewing its current air quality permits with regard to MMC’s methane production and deliveries were suspended during that review. Eastman has now indicated to MMC in early March 2009 that it is prepared to commence taking delivery of the methane gas from MMC’s Carter Valley facility. Accordingly, MMC expects to declare startup of commercial operations no later than the end of March 2009. Thereafter, MMC, Eastman Chemical, and Republic Services intend to schedule a formal grand opening of this facility in the spring of 2009.

Prior to declaring startup of commercial operations, MMC continues to fully integrate the gas supply from the landfill with the operations of the methane extraction equipment to maximize quality and quantity of the gas produced and to enable continuous daily production from the facility. The Company believes that this process is complete as of the date of this Report. To date, MMC has produced approximately 800 thousand cubic feet of methane gas that was extracted from the landfill gas. The produced methane was mixed with the natural gas produced from the Company’s Swan Creek field and delivered to Eastman through the new 2.5 mile pipeline built from the landfill to connect with the Company’s existing 65-mile natural gas pipeline.

The methane gas produced to date is of the high quality levels and heating content that MMC expected with the system design. MMC expects to be able to continuously produce and sell about 500 MCF per day, which significantly exceeds the original estimate of about 418 MCF per day that was made at the beginning of this project. This has happened because the landfill has grown during the time the Project has been in planning and construction, and the landfill owner Republic has improved both the quality and volume of gas collected by the gas gathering system in the landfill itself.

On September 17, 2007, Hoactzin, simultaneously with subscribing to participate in the Ten Well Program (the “Program”), pursuant to a separate agreement with the Company was conveyed a 75% net profits interest in the Methane Project. 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 could accelerate reaching the Payout Point. As stated above, the Purchase Price paid by Hoactzin for its interest in the Program exceeded the Company’s anticipated and actual costs of drilling the ten wells in the Program. 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 element to the Company of the overall transaction.

4. Management Agreement with Hoactzin

The Company entered into a Management Agreement with Hoactzin on December 17, 2007. 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 for a corresponding price of up to 15% of the actual project costs, in any new drilling or work-over activities undertaken on Hoactzin’s managed properties during the term of the Management Agreement. During 2008, the Company did not exercise any option to participate in any such operation.

The term of the Management Agreement is the earlier of the period ending with the date Hoactzin sells its interests in its managed properties or 5 years from the date of the Agreement.

5. Other Areas of Development

The Company is continuing to review and analyze potential acquisitions of additional existing oil and gas production in the Mid-Continent (USA) area. The Company is particularly interested in areas of Kansas, Oklahoma, and Texas. Whether the Company will proceed with any such acquisition it deems appropriate will be dependent on a number of factors, including available financing, oil prices, etc. Current economic conditions, including the sharp decline in oil prices, will certainly have an adverse impact on the Company’s ability to acquire additional properties. Accordingly, there is no assurance that a suitable property will become available or even if such property becomes available that terms will be established leading to a completion of such a purchase.

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

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

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

Principal Products or Services and Markets

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

Gas production from the Swan Creek Field can presently be delivered through the Company’s completed pipeline to the Powell Valley Utility District in Hancock County, Eastman and BAE in Sullivan County, as well as other industrial customers in the Kingsport area. The Company has acquired all necessary regulatory approvals and necessary property rights for the pipeline system. The Company's pipeline cannot only provide transportation service for gas produced from the Company's wells, but could provide transportation of gas for small independent producers in the local area as well or other pipelines that may be connected to the Company’s pipeline in the future. The Company could, although there can be no assurance, sell its products to certain local towns, industries and utility districts.

At present, crude oil produced by the Company in Kansas is sold at or near the wells to the Coffeyville Resources Refining and Marketing, LLC (“Coffeyville Refining”) in Kansas City, Kansas. Coffeyville Refining is solely responsible for transportation to its refinery of the oil it purchases. The Company may sell some or all of its production to one or more additional refineries in order to maximize revenues as purchase prices offered by the refineries fluctuate from time to time. Crude oil produced by the Company in Tennessee is sold to the Ashland refinery in Kentucky and is transported to the refinery by contracted truck delivery at the Company’s expense.

Drilling Equipment

The Company does not currently own a drilling rig or any related drilling equipment. The Company obtains drilling services as required from time to time from various companies as available in the Swan Creek Field area and various drilling contractors in Kansas.

Distribution Methods of Products or Services

Crude oil is normally delivered to refineries in Tennessee and Kansas by tank truck and natural gas is distributed and transported via pipeline.

Sources and Availability of Raw Materials

Excluding the development of oil and gas reserves and the production of oil and gas, the Company's operations are not dependent on the acquisition of any raw materials.

Dependence On One or a Few Major Customers

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

At present, crude oil from the Kansas Properties is being purchased at the well and trucked by Coffeyville Refining, which is responsible for transportation of the crude oil purchased. The Company may sell some or all of its production to one or more additional refineries in order to maximize revenues as purchase prices offered by the refineries fluctuate from time to time.

Patents, Trademarks, Licenses, Franchises, Concessions,

Royalty Agreements or Labor Contracts, Including Duration

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

Research and Development

The Company has not expended any material amount in research and development activities during the last two fiscal years. The Company, however, spent substantial amounts in 2006 and 2007 for the acquisition of seismic data relating to the Company’s Kansas Properties and for three-dimensional analysis of the acquired seismic data for the purpose of determining drilling targets with the maximum likelihood of being commercial producers of oil when drilled. The Company’s success in 2008 was in large part a result of these investments. The information developed also led to creating an inventory of wells to be drilled. However, recent lower oil prices and the fact that the Company has historically drilled with revenues generated primarily from the Company’s operations may limit the development of these drilling targets and restrict the Company’s drilling program. In addition, volumes from these drilling targets has been excluded from the Company’s current reserve report as of December 31, 2008 since their financial value when future revenues are discounted as a standard measure appears commercially unreasonable at $34.00 per barrel of oil, the 2008 year-end price of oil required to be used under SEC regulations.