Edgar Filing: TENGASCO INC

U.S. Securities and Exchange Commission

Washington, D.C. 20549

Form 10-Q

QUARTERLY REPORT UNDER SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly period ended September 30, 2006

Commission File No. 0-20975

Tengasco, Inc. and Subsidiaries

(Exact name of issuer as specified in its charter)

Tennessee	87-0267438
State or other jurisdiction of	(IRS Employer Identification No.)
Incorporation or organization

10215 Technology Drive N.W. Suite 301

Knoxville, TN 37932

(Address of principal executive offices)

(865-675-1554)

(Issuer’s telephone number, including area code)

Indicate by check mark whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes X

No__

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes____ No X

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date: 58,981,017 common shares at September 30, 2006.

TENGASCO, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION	PAGE
	ITEM 1. FINANCIAL STATEMENTS
	* Condensed Consolidated Balance Sheets as of September 30, 2006 and December 31, 2005	3-4

	* Condensed Consolidated Statements of Operations for the three and nine months ended September 30, 2006 and 2005	5

	* Condensed Consolidated Statements of Stockholders’ Equity for the nine months ended September 30, 2006	6

	* Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2006 and 2005	7

	* Notes to Condensed Consolidated Financial Statements	8-16

	ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	16-23

	ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK	24

	ITEM 4. CONTROLS AND PROCEDURES	25

PART II.	OTHER INFORMATION
	ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	25-26

	ITEM 5. OTHER INFORMATION	26-27

	ITEM 6. EXHIBITS	28

	* SIGNATURES	28

	* CERTIFICATIONS	29-32

TENGASCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

	September 30, 2006 (unaudited)	December 31, 2005

Assets

Current
Cash and cash equivalents	$ 619,436	$ 260,969
Accounts receivable	1,056,204	1,154,405
Participant receivables	12,340	9,777
Inventory	452,059	496,331
Other current assets	11,056	6,056

Total current assets	2,151,095	1,927,538

Restricted cash (Note 9)	120,500	-
Loan fees (Note 8)	261,175	-

Oil and gas properties, net (on the basis of full cost accounting)	11,726,902	9,675,877

Pipeline facilities, net	13,596,279	13,994,453
Other property and equipment, net	254,722	310,748


	$ 28,110,673		$ 25,908,616

See accompanying notes to condensed consolidated financial statements

TENGASCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND STOCKHOLDERS’ EQUITY

		September 30, 2006 (Unaudited)	December 31, 2005



Current liabilities
Current maturities of long-term debt	$ 33,868			$ 58,867
Accounts payable	903,439			597,278
Other accrued liabilities	117,542			281,737
Drilling program (Note 5)	-			2,324,400

Total current liabilities	1,054,849			3,262,282

Asset retirement obligations (Note 6)	546,295			566,968
Long term debt, less current maturities (Note 8)	2,735,472			117,912

Total liabilities	4,336,616			3,947,162


Stockholders’ equity
Common stock, $.001 par value; authorized 100,000,000 shares; 58,981,017 and 58,604,678 shares issued and outstanding	58,981			58,605
Additional paid-in capital	54,456,362			54,200,345
Accumulated deficit	(30,741,286)			(32,297,496)

Total stockholders’ equity	23,774,057			21,961,454
	$ 28,110,673			$ 25,908,616

See accompanying notes to condensed consolidated financial statements

TENGASCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	For the Three Months Ended September 30,		For the Nine Months Ended September. 30,
	2006	2005	2006	2005
Revenues and other income
Oil and gas revenues	$ 2,219,667	$ 1,853,885	$ 6,624,083	$ 4,851,227
Pipeline transportation revenues	22,134	25,683	67,625	70,338
Interest income	9,473	21	13,271	1,139

Total revenues and other income	2,251,274	1,879,589	6,704,979	4,922,704

Cost and other deductions
Production costs and taxes	732,473	747,705	2,399,324	2,229,188
Depletion, depreciation and amortization	503,665	473,875	1,315,445	1,431,029
Interest expense	97,318	105,913	146,355	458,903
General and administrative cost	384,245	412,869	1,122,091	1,019,719
Public relations	1,103	605	25,184	1,786
Professional fees	13,376	54,263	140,370	248,611
Total cost and other deductions	1,732,180	1,795,230	5,148,769	5,389,236
Gain from extinguishment of debt	-	577,422	-	577,422
Net income	519,094	$ 661,781	1,556,210	$ 110,890

Net income per share Basic and diluted: Operations	$ 0.01	$ 0.01	$ 0.03	$ 0.00
Total	$ 0.01	$ 0.01	$ 0.03	$ 0.00

Shares used in computing Earnings Per Share
Basic	58,969,212	51,374,620	58,802,166	49,750,556
Diluted	60,373,143	52,014,620	60,206,097	50,390,556

See accompanying notes to condensed consolidated financial statements

TENGASCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Unaudited)

	Common Stock
	Shares	Amount	Additional Paid in Capital	Accumulated Deficit	Total
Balance at December 31, 2005	58,604,678	$ 58,605	$ 54,200,345	$ (32,297,496)	$ 21,961,454

Net income	-	-	-	1,556,210	1,556,210

Options & compensation expense	364,500	365	250,701	-	251,066

Common stock issued for exercise of warrants	11,839	11	5,316	-	5,327

Balance September 30, 2006 (Unaudited)	58,981,017	58,981	54,456,362	(30,741,286)	23,774,057

See accompanying notes to condensed consolidated financial statements

TENGASCO, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

	For the Nine Months Ended Sept. 30, 2006 (unaudited)	For the Nine Months Ended Sept. 30, 2005 (unaudited)

Operating activities
Net Income	$ 1,556,210	$ 110,890
Adjustments to reconcile net income to net cash Provided by operating activities:
Depletion, depreciation, and amortization	1,315,445	1,431,029
Accretion of redeemable shares	-	246,007
Accretion on Asset Retirement Obligation	67,644	39,007
Gain on extinguishment of Asset Retirement Obligation	-	(72,399)
(Gain)/loss on sale of vehicles/equipment	(22,565)	12,670
Gain on exchange of redeemable liabilities	-	(577,422)
Gain on sale of pipeline facilities	-	(17,605)
Compensation and services paid in stock options	108,186	74,470
Changes in assets and liabilities:
Accounts receivable	98,201	(149,270)
Participant receivables	(2,563)	65,174
Other current assets	(5,000)	61,354
Inventory	44,272	(83,678)
Accounts payable	306,161	65,056
Accrued interest payable	-	(25,367)
Other accrued liabilities	(164,195)	(10,146)
Settlement on Asset Retirement Obligations	(88,218)	(48,004)
Net cash provided by operating activities	3,213,578	1,121,766

Investing activities
Additions to other property & equipment	(83,026)	(86,583)
Restricted cash	(120,500)	-
Decrease to other property & equipment	27,915	-
Net additions to oil and gas properties	(3,868,425)	(90,924)
Sale of Kansas gas field (See Note 8)	-	2,350,000
Drilling program portion of additional drilling	1,067,400	-
(Increase)/decrease in pipeline facilities	(9,826)	95,395
Net cash provided by (used in) investing activities	(2,986,462)	2,267,888

Financing activities
Exchange of Redeemable Liabilities	-	(4,435,889)
Proceeds from exercise of options/warrants	148,207	-
Proceeds from borrowings	2,677,636	1,920,721
Loan fees	(284,918)	-
Repayments of borrowings	(85,174)	(2,459,972)
Decrease in Drilling Program liability	(2,324,400)	(1,316,702)
Dividends paid on redeemable liabilities	-	(8,000)
Exchange of redeemable liabilities for cash & common stock	-	2,731,318
Net cash provided by (used in) financing activities	131,351	(3,568,524)

Net change in cash and cash equivalents	358,467	(178,870)

Cash and cash equivalents, beginning of period	260,969	267,735
Cash and cash equivalents, end of period	$ 619,436	$ 88,865

See accompanying notes to condensed consolidated financial statements

Tengasco, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(Unaudited)

(1)

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles for interim financial information and with the instructions to Form 10-Q and Item 210 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. In the opinion of management, all adjustments (consisting of only normal recurring accruals) considered necessary for a fair presentation have been included. Operating results for the nine months ended September 30, 2006 are not necessarily indicative of the results that may be expected for the year ended December 31, 2006. No income tax expense was recognized for the nine months ended September 30, 2006 because deferred tax benefits, derived from the Company’s prior net operating losses, were previously fully-reserved and are being offset against liabilities that would otherwise arise from the results of current operations. Additionally, deferred income tax assets and liabilities are not reflected in the Company’s financial statements. Management continuously estimates the realization of its deferred tax assets based on its assessment of the likely timing and adequacy of future net income that will be generated from sales in a volatile commodity market, at prices over which the Company has no control. Based on its assessment, for each of the nine months ending September 30, 2006 and 2005, management reserved the gross tax benefit. Certain prior year amounts have been reclassified to conform with current year presentation. For further information, refer to the Company’s consolidated financial statements and footnotes thereto included in the Company’s annual report on Form 10-K for the year ended December 31, 2005.

(2)

Earnings per Share

In accordance with Statement of Financial Accounting Standards (SFAS) No. 128, “Earnings Per Share” (“SFAS 128”), basic income per share is based on 58,969,212 and 51,374,620 weighted average shares outstanding for the quarters ended September 30, 2006 and September 30, 2005 respectively, and 58,802,166 and 49,750,556 for the nine months ended September 30, 2006 and September 30, 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.

The number of dilutive shares outstanding is 1,403,931 and these are related to options and warrants for 2006 and 640,000 for 2005.

The Company adopted the disclosure provision of the Statement of Financial Accounting Standards (SFAS or Statement) No.148, “Accounting for Stock-Based Compensation-Transition and Disclosure” (“SFAS 148”), which amends SFAS No. 123 “Accounting for Stock-Based Compensation”, (“SFAS 123”). SFAS 148 provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock-based employee compensation, which was originally provided under SFAS 123. The Statement also improves the timeliness of disclosures by requiring the information be included in interim, as well as annual, financial statements.

The Company issued 740,000 stock options on September 9, 2005 to officers and directors and granted 200,000 stock options in January 2006. The Company also granted 26,500 shares to the members of the Audit Committee for services. The Company calculated the fair value per share of options granted using the Black Scholes pricing model. Compensation expense relating to stock options and shares granted in the amount of $27,406 was recognized in the third quarter of 2006 and $108,186 for the nine months ended September 30, 2006.

(3)

Recent Accounting Pronouncements

In December 2004, the Financial Accounting Standards Board (FASB) published Statement of Financial Accounting Standards (SFAS) No. 123 (revised 2004), (SFAS 123(R)) “Share Based Payment”. SFAS 123(R) establishes standards for the accounting for transactions in which an entity exchanges its equity instruments for goods or services. SFAS 123(R) eliminates the ability to account for share-based compensation transactions using APB Opinion No. 25 (APB 25), “Accounting for Stock Issued to Employees”, and generally requires that such transactions be accounted for using a fair-value-based method. This statement is effective for fiscal years beginning after June 15, 2005. SFAS 123(R) applies to all awards granted after the required effective date and to awards modified, repurchased, or cancelled after that date and as a consequence, future employee stock option grants and other stock based compensation plans will be recorded as expense over the requisite service period of the award based on their fair values at the date the stock based compensation is granted. The cumulative effect of initially applying SFAS 123(R) is to be recognized as of the required effective date using a modified prospective method. Under the modified prospective method the Company recognized stock-based compensation expense from July 1, 2005 as if the fair value based accounting method had been used to account for all outstanding unvested employee awards granted, modified or settled in prior years. The Company adopted SFAS 123(R) in 2005 and recognized $84,030 in compensation expense for options granted in 2005. The Company expects to recognize $109,620 in 2006 and 2007 in compensation expense relating to these options granted in 2005 and $75,357 relating to options granted in 2006. The ultimate impact on results of operation and financial position in future years will depend upon the level of stock-based compensation granted.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Correction — a replacement of APB Opinion No. 20 and FASB Statement No. 3.” This statement changes the requirements for the accounting for and reporting of a change in accounting principle and applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. APB No. 20 required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This statement requires retrospective application to prior period financial statements of changes in accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. The provisions of SFAS No. 154 are effective for fiscal years beginning after December 15, 2005. The Company does not expect that the adoption of SFAS No. 154 will have an impact on the Company’s financial statements.

(4)

Related Party Transactions

On May 18, 2004, Dolphin Offshore Partners L.P. (“Dolphin”) loaned the Company $2,500,000 bearing interest at 12% per annum with interest payable monthly beginning June 18, 2004 and principal payable on May 20, 2005, which loan was secured by a lien on the Company’s Tennessee and Kansas producing properties and the Tennessee pipeline. Peter E. Salas, the Chairman of the Company’s Board of Directors and the sole shareholder and controlling person of Dolphin Management, Inc. the general partner of Dolphin, negotiated the terms of the loans directly with management, which terms were approved by management in view of the Company’s immediate needs, financial condition and prospective alternatives and under circumstances in which Dolphin was not generally engaged in the business of lending money. These loans were made on terms that management believed were at least as favorable to the Company as it could have obtained through arms-length negotiations with unaffiliated third parties.

On December 30, 2004, Dolphin loaned the Company $550,000 bearing interest at 12% per annum with interest payable monthly and principal payable on May 20, 2005, which loan was secured by lien on the Company’s Tennessee and Kansas properties. On March 4, 2005, Dolphin was paid $2,350,000 from the proceeds received from the sale of the Company’s Kansas gas field to reduce the principal of the promissory note dated May 18, 2004 in the original amount of $2,500,000, to $150,000. With this payment, the combined balances owed on the two outstanding notes to Dolphin at March 31, 2005 became $700,000.

On May 19, 2005 these two notes were replaced with a single new note to Dolphin for $700,000 payable on August 20, 2005. By an amended and restated note dated August 18, 2005, the due date of the note was extended on the same terms as the existing note from August 20, 2005 to December 31, 2005.

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 an 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. 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 borrowed the sum of $1,814,000 from Dolphin to fund this exchange of cash for Series B and C Preferred Stock. (See Note 5 to the Financial Statements). The loan from Dolphin was evidenced by a secured promissory note bearing 12% interest per annum payable interest only monthly until the principal amount of the note was to become due on December 31, 2005. 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. On October 5, 2005, Hoactzin Partners, L.P. ("Hoactzin") surrendered to the Company the two outstanding promissory notes dated December 30, 2004 and August 22, 2005 made by the Company to Dolphin in the aggregate principal amount of $2,514,000. In exchange for the surrender of these notes, the Company entered into an agreement granting Hoactzin a 94.3% working interest in a twelve-well drilling program to be undertaken by the Company on its properties in Kansas. The Company retains the remaining 5.7% working interest in the drilling program.

On June 29, 2006 the Company used $1.393 million of the proceeds of a $2.6 million loan from Citibank Texas, N.A. (See Note 8 to Financial Statements,) to exercise the Company’s option to repurchase from Hoactzin the Company’s obligation to drill for Hoactzin the final six wells of the Company’s 12-well Kansas drilling program. The controlling person of Hoactzin is Dolphin Advisors, LLC, an entity controlled by Peter E. Salas, the Company’s Chairman of the Board. If the Company had not exercised its repurchase option, Hoactzin would have received a 94% working interest in the final six wells of the program until payout as established in the terms of the drilling program. However, as a result of the terms of the repurchase option exercised by the Company, 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 12-well program was converted into a 6-well program, and because six wells have already been drilled by the Company as of June 30, 2006 the drilling obligation in this program was satisfied. Consequently, as of June 30, 2006, all well-drilling obligations of the Company owed to participants have been satisfied as to both the 8-well drilling program

(offered to the former Company’s Series A preferred stockholders) and the 12-well drilling 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). The participants will continue to receive the agreed upon revenues allocable to their working interest until payouts under the programs occur, at which time the Company will begin to receive a management fee of 85% of those participants’ working interest proceeds for the remaining life of the wells.

(5)

Cumulative Convertible Preferred Stock and Drilling Program

Primarily before 2002, the Company issued two classes of preferred stock (Series A and Series B). Shares of both Series A and B of Preferred Stock were immediately convertible into shares of Common Stock. Each $100 liquidation preference share of preferred stock was convertible at a rate of $7.00 for the Series A per share of common stock. The Series B shares were convertible at the rate of average market price of the Company’s common stock for 30 days before the sale of the Series B preferred stock with a minimum conversion price of $9.00 per share. The conversion rate was subject to downward adjustment for certain events.

During 2002, the Board of Directors authorized the sale of up to 50,000 shares of a third series, Series C Preferred Stock at $100 per share. The Company issued 14,491 shares, resulting in net proceeds after commissions of $1,303,168. The Series C Preferred Stock accrued a 6% cumulative dividend on the outstanding balance, payable quarterly and was convertible into the Company’s common stock at the average stock trading price 30 days prior to the closing of the sales of all the Series C Preferred Stock being offered or $5.00 per share, whichever was greater. The Company was required to redeem any remaining Series C Preferred Stock and any accrued and unpaid dividends in May 2007.

The Company adopted the provisions of SFAS No. 150 “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Debt” (“SFAS 150”) on July 1, 2003. Under SFAS 150, mandatorily redeemable preferred stock shall be reclassified at fair value to a liability. The Company determined that each of the Series A, Series B and Series C preferred stock qualify as shares subject to mandatory redemption, and as such, were reclassified as liabilities upon adoption of SFAS150. Accordingly, the difference between the carrying amount at the date of adoption and the fair value of the shares (discounted at rates between 12% and 12.5%) was recognized as a cumulative effect of a change in accounting principle of $365,675 effective July 1, 2003. The difference between the carrying amount of shares subject to mandatory redemption and the face value amount of preferred stock is being accreted at rates between 12% and 12.5% into interest expense and the liability until conversion or redemption of the shares. Accretion associated with these shares subject to mandatory redemption from July 1, 2003 through December 31, 2003 was $354,735 and $752,003 for 2004 and $242,007 in 2005.

In December, 2004, the Company completed an exchange offer to thirteen holders of the Company’s Series A 8% Cumulative Convertible Preferred Stock in the amount of $2,867,900. Seven of the thirteen holders elected a cash exchange option, and the face amount of $1,085,000 of Series A shares was exchanged on or before December 31, 2004 for cash payments of $723,370. A gain was recorded on this transaction in the amount of $458,310, the difference between the carrying amount and the cash settlement amount. The Company obtained funds for the exchange from cash on hand and the proceeds of a loan from Dolphin. The loan from Dolphin was in the form of a secured note in principal amount of $550,000 bearing 12% interest per annum payable interest only until due on May 20, 2005. Five of the thirteen Series A holders elected to participate in a drilling program (“Drilling Program”) in exchange for their preferred Shares, and on December 31, 2004 the amount of $1,582,900 of Series A shares plus accrued dividend of $31,658 was exchanged for approximately 6.5 units in the Drilling Program. A liability was recorded for the Drilling Program in the amount of $1,755,603 and “Shares subject to mandatory redemption” was reduced by the same amount. The Drilling Program liability recorded represents the estimated fair value of the liability calculated upon adoption of SFAS 150 less accretion, from such date to the date of the exchange. The remaining 1.5 units in the Drilling Program continue to be owned by the Company.

Under the terms of the Drilling Program, the former Series A holders participating will receive all the cash flow from each of eight wells drilled until they have recovered 80% of the value of the Series A shares exchanged. At that point, the Company will begin to receive 85% of the cash flow from these wells as a management fee, and the former Series A owners will continue to receive 15% of the cash flow for the productive life of the wells.

In summary, twelve of the 13 holders of Series A preferred stock exchanged their Series A shares. As a result, as of December 31, 2004, the Company had remaining only one Series A shareholder, in face amount of $200,000. On December 30, 2005 the Company reached an agreement to exchange the last remaining Series A 8% Cumulative Convertible Preferred Stock in the face amount of $200,000 plus $12,000 of accrued dividends for a cash settlement of $145,400. The payment was made on January 3, 2006. The $145,400 liability as of December 31, 2005 was recorded as an accrued liability on the balance sheet and a gain of $78,324 was recorded, the difference between the carrying amount of the preferred stock and the cash settlement amount.

During 2005 the Company completed six wells of the eight well Drilling Program and completed the program drilling in the second quarter of 2006. The Company reduced the Drilling Program liability by $1,755,602 and offset oil and gas properties by the corresponding amount.

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. The note was exchanged for a twelve well Drilling Program on October 5, 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 was 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.

(6)

Asset Retirement Obligation

In accordance with SFAS 143, the Company has recorded 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. The Company’s asset retirement obligations relate primarily to the plugging, dismantling, and removal of wells drilled to date.

Management determined that the following assumptions in estimating the initial recording of the Company’s Asset Retirement Obligation were appropriate: using a credit-adjusted risk free rate of 12%; an estimated useful life of wells ranging from 30-40 years; and estimated plugging and abandonment costs ranging

from $5,000 to $10,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions. Management believes these assumptions are appropriate as of September 30, 2006.

For the nine months of 2006 and 2005, the Company recorded accretion expenses of $67,644 and $39,007 associated with this liability. These expenses are included in interest expense in the Consolidated Statements of Operations.

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 was 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.

(7)

Sale of Kansas Properties

On March 4, 2005 the Company sold its Kansas gas wells, leases and the associated gathering system in place in Rush County, Kansas to Bear Petroleum, Inc. for $2.4 million. The Company’s gas producing properties in Kansas were physically separated from the oil properties, and were all located in Rush County, Kansas consisting of 51 producing gas wells and associated gathering system. All proceeds of this sale, being the sales price less a sales commission of $50,000, were immediately paid to Dolphin Offshore Partners, L.P. to reduce the principal of the promissory note to Dolphin in the original amount of $2.5 million, to $150,000. (See note 4 to the financial statements.) The Company recorded a credit to oil and gas properties of $2,350,000, the sale price net of commission.

(8)

Bank Loan

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. $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 $284,918. This amount will be amortized over the term of the note. For the quarter ended September 30, 2006, $23,743 was amortized.

(9)

Restricted Cash

As security required by Tennessee oil and gas regulations, the Company placed $120,500 in a Certificate of Deposit to cover future asset retirement obligations for the Company’s Tennessee wells.

ITEM 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Results of Operations and Financial Condition

Kansas

During the first nine months of 2006, the Company produced and sold 133,216 barrels of oil from its Kansas Properties comprised of 143 producing oil wells. Of the 133,216 barrels produced and sold, 88,808 barrels were payable to the Company’s interest after required payments to all of the Drilling Program participants and royalty interests. The Company’s first nine months production in 2006 of 88,808 barrels of oil compares to 68,282 barrels produced to the Company’s interest in the first nine months of 2005. The Company’s net revenues from the Kansas properties were $5,589,577 in the first nine months of 2006 compared to $3,588,918 in 2005. This increase was due to increased production of 20,526 barrels to the Company’s interest and higher prices for oil.

Tennessee

During the first nine months of 2006, the Company produced gas from 23 wells in the Swan Creek field, which it primarily sold in Kingsport, Tennessee to Eastman Chemical Company. Natural gas production from the Swan Creek field for the first nine months of 2006 was an average of 401 Mcf per day during that period as compared to 500 Mcf per day in the first nine months of 2005. The first nine months production reflected expected natural decline in production from the existing Swan Creek gas wells which were first brought into production in mid-2001. For the first nine months of 2006 the Company produced 6,587 barrels of oil as compared to 8,015 in 2005. This natural decline is normal for any producing oil well, and this decline as experienced on existing oil wells in Swan Creek was not unexpected.

Comparison of the Nine Months Ended September 30, 2006 and 2005

The Company recognized $6,704,979 in total revenues from its Kansas Properties and the Swan Creek Field during the first nine months of 2006 compared to $4,922,704 in the first nine months of 2005. The increase in revenues was due to an increase in oil prices in 2006 and a 20,526 barrel increase allocable to the Company’s interest in oil production from the Kansas Properties. This Kansas oil production increase is attributable to 2 new wells, well workovers, polymer completion workovers and the Company’s portion (19%) of its eight-well Drilling Program. Oil prices in the first nine months of 2006 averaged $62.94 per barrel as compared to $52.56 per barrel in the first nine months of 2005.

The Company realized a net income attributable to common shareholders of $1,556,210 or $0.03 per share of common stock during the first nine months of 2006, compared to a net income in the first nine months of 2005 to common shareholders of $110,890 or $0.00 per share of common stock. The Company recorded a gain from the exchange of Series B and C cumulative preferred stock for cash and stock of $577,422 in the third quarter of 2005, the difference between the carrying amount and the cash settlement and stock issued.

Production costs and taxes in the first nine months of 2006 increased to $2,399,324 from $2,229,188 in the first nine months of 2005. The difference is due to increased workovers to increase production and overall cost increases of supplies in the industry.

Depletion, depreciation, and amortization expense for the first nine months of 2006 was $1,315,445 compared to $1,431,029 in the first nine months of 2005. This is due to a reduction in depletion. Increased production and increased reserve base resulted in this reduction in depletion. The 2005 Ryder Scott Report is the basis for the depletion calculation. Ryder Scott has performed reserve analysis of all the Company’s productive leases.

During the first nine months of 2006, general and administrative costs increased to $1,122,091 from $1,019,719 in the first nine months of 2005 due partly to $108,186 in compensation expense charged relating to stock options.

Professional fees in the first nine months of 2006 were $140,370 compared to $248,611 in the same period in 2005. These fees have decreased as all material litigation has been resolved.

Interest expense for the first nine months of 2006 decreased to $146,355 from $458,903 in the first nine months of 2005. The substantial decrease is the result of the payoff of the Dolphin notes and the conversion of shares subject to

mandatory redemption in 2005, primarily offset by interest on the Citibank loan of $58,890 in the third quarter of 2006.

Comparison of the Quarters Ended September 30, 2006 and 2005

The Company recognized $2,251,274 in total revenues from its Kansas Properties and the Swan Creek Field during the third quarter of 2006 compared to $1,879,589 in the third quarter of 2005. The increase in revenues was due mainly to increased production by 6,194 barrels allocable to the Company’s interest in the third quarter of 2006 over 2005 levels. Oil prices also increased over 2005 levels. Oil prices in the third quarter of 2006 averaged $64.97 per barrel as compared to $59.50 per barrel in the third quarter of 2005.

The Company realized a net income attributable to common shareholders of $519,094 or $0.01 per share of common stock during the third quarter of 2006, compared to a net income in the third quarter of 2005 to common shareholders of $661,781 or $0.01 per share of common stock. The Company recorded a gain from the exchange of Series B and C cumulative preferred stock for cash and stock of $577,422 in the third quarter of 2005, the difference between the carrying amount and the cash settlement and stock issued.

Production costs and taxes in the third quarter of 2006 of $732,473 remained consistent with $747,705 incurred in the third quarter of 2005.

Depletion, depreciation, and amortization expense for the third quarter of 2006 of $503,665 remained consistent compared to $473,875 in the third quarter of 2005.

During the third quarter of 2006, general and administrative costs of $384,245 decreased slightly from $412,869 incurred in the third quarter of 2005.

Professional fees in the third quarter of 2006 were $13,376 compared to $54,263 in the same period in 2005.

Interest expense for the third quarter of 2006 of $97,318 remained consistent with $105,913 paid in the third quarter of 2005.

Liquidity and Capital Resources

Management believes that the Company’s foundation for its future growth began to solidify in 2004. In 2004, all material litigation involving the Company was resolved, eliminating the substantial related costs and expenses of such litigation. Capital restructuring began in February 2004, when the Company’s rights offering to its then-shareholders successfully raised sufficient capital to pay in full all pre-existing secured debt in the amount of $3.8 million, most of which

had been obtained at relatively high interest rates. Also in early 2004 certain unsecured convertible notes entered into in 1998 in the principal amount of $1.5 million were fully paid, and still other convertible notes entered into in 2002 in the original principal amount of $650,000 were paid in full in March 2004. In December, 2004 the Company completed an exchange offer to the thirteen holders of all of the Company’s Series A 8% Cumulative Convertible Preferred Stock (“Series A Shares”) in the face value of $2,867,900. Seven of the thirteen holders elected a cash exchange option, and the face value of $1,085,000 of Series A Shares was exchanged for a cash payment of $723,369. The Company obtained funds for the exchange from cash on hand and the proceeds of a loan from Dolphin Offshore Partners, L.P. (“Dolphin”), the Company’s largest shareholder. Peter E. Salas, the Chairman of the Company’s Board of Directors is the sole shareholder and controlling person of Dolphin Management, Inc., the general partner of Dolphin. The loan from Dolphin was in the form of a secured note in principal amount of $550,000 bearing 12% interest per annum. Five of the thirteen Series A shareholders selected a drilling program exchange option and on December 31, 2004 the face value of $1,582,900 of Series A Shares plus dividend value of $31,658 was exchanged for 6.5 of the eight units in the Company’s Eight Well Program. In December 2005 the last remaining Series A preferred shareholder exchanged his preferred stock for cash on terms essentially identical to those received by the other Series A owners who had exchanged their shares for cash.

In early 2005, the Company elected to sell its gas producing properties in Rush County, Kansas for $2.4 million and to utilize all the net proceeds of the sale to pay down the $2.5 million debt to Dolphin incurred by the Company to fund the settlement of the litigation with the Company’s former primary lender, Bank One N.A., in May, 2004. This had the effect of reducing the principal balance of the note evidencing that loan from $2.5 million to $150,000, correspondingly reducing the high interest payments on that note and reducing the total secured debt owed by the Company to Dolphin to approximately $700,000 as of March 31, 2005, consisting of the $150,000 remaining principal of the $2.5 million note, and the principal of the $550,000 note described above which evidenced the loan from Dolphin, the proceeds of which were used by the Company to fund the cash exchange payment for the Series A Shares. On May 19, 2005, a replacement note in the principal amount of $700,000 bearing interest at the rate of 12% per annum evidencing this secured debt was issued by the Company to Dolphin (the “$700,000 Note”).

In August 2005, all of the holders of the Company’s Series B 8% and C 6% Cumulative Convertible Preferred Stock (the “Series B and Series C Shares”) in the total aggregate value of $5,113,045 consisting of face value, dividends, and interest exchanged their Series B and C Shares for cash or for the Company’s common stock. The cash option exchange provided for a cash payment equal to 66.67% of the face value together with any unpaid accrued dividends. Holders of approximately 53.2% of the face value of outstanding Series B and C Shares selected this option, exchanging preferred shares having an aggregate value of $2,721,140.39 for cash payments totaling $1,814,184.

The Company obtained the funds for this exchange primarily from proceeds of a loan of $1,814,000 from Dolphin evidenced by a secured promissory note bearing 12% interest (the “$1,814,000 Note”). The second option offered to the holders of the Series B and C Shares was to exchange their Series B and C Shares for four shares of the Company’s common stock for each dollar of the face value and unpaid accrued dividends and interest on their Series B and C Shares. The holders of the remaining aggregate value of $2,391,905 or 46.8% of the Series B and C shares including Dolphin selected this option. As a result, a total of 9,567,620 shares of the Company’s common stock were issued to holders of Series B and C Shares. Of this total number, 4,595,040 shares of unregistered common stock were issued to Dolphin in exchange for the $1,148,760 in aggregate value of the Series B shares held by Dolphin. As a result of this exchange, as of August 22, 2005, the Company no longer had any Series B or C preferred stockholders and no further obligations under the Series B or C Shares.

On October 5, 2005 the Company and Hoactzin Partners, L. P. (“Hoactzin”) signed an agreement whereby Hoactzin, an affiliate of Dolphin, surrendered the $700,000 and $1,814,000 Notes, which had been assigned to it by Dolphin, and exchanged the Company’s obligation to repay this principal amount of $2.514 million for a 94.275% working interest in a new twelve well drilling program (the “Twelve Well Program”) to be undertaken by the Company on its properties in Kansas. The Company retained the 5.725% working interest in the Twelve Well Program not owned by Hoactzin. The principal of the Notes exchanged by Hoactzin represented the funds paid by the Company for the previous exchanges by holders of the Company’s Series A, B, and C preferred stock of their preferred stock for cash. Under the terms of the Twelve Well Program, the Company retained an option to repurchase from Hoactzin the obligations to drill the final six wells of the Twelve Well Program for one half of the principal of notes exchanged by Hoactzin, plus interest on that amount at 6% per annum until the date of any repurchase, plus a 1/16 overriding royalty to Hoactzin on all wells drilled in the Twelve Well Program. Payout and management fee calculations would also be adjusted to reflect any reduction to a six well program. Hoactzin agreed to extend the expiration date of the repurchase option from March 31, 2006 to an indefinite future date being not later than the beginning of drilling of what would be the seventh well in the program if the repurchase option has not been exercised.

As a result of the above exchanges of preferred stock and notes for interests in the Eight and Twelve Well Programs, as of December 31, 2005, the Company had reduced its liabilities in the form of face amount of preferred stock and secured promissory notes from approximately $16 million as of December 31, 2003 to $0, the Company no longer had any preferred stock outstanding, and the Company no longer had any liens on any of its oil and gas properties or pipelines. The Company’s only substantial liability was its contractual obligation to drill the wells in the Eight and Twelve Well Programs in the amount of 2.3 million.

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

On June 29, 2006 the Company used $1.393 million of the proceeds of the $2.6 million loan to exercise the Company’s option to repurchase from Hoactzin Partners, L.P., the Company’s obligation to drill for Hoactzin the final six wells of the Company’s Twelve Well Program. The controlling person of Hoactzin is Dolphin Advisors, LLC, an entity controlled by Peter E. Salas, the Company’s Chairman of the Board. If the Company had not exercised its repurchase option, Hoactzin would have received a 94% working interest in the final six wells of the Program until payout as established in the terms of the drilling program. However, as a result of the terms of the repurchase option exercised by the Company on June 29, 2006 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 have already been drilled by the Company as of June 30, 2006 the drilling obligation in this program is satisfied. Consequently, as of June 30, 2006, all well-drilling obligations of the Company owed to participants have been satisfied as to both the Eight Well Program (offered to the former Series A preferred stockholders) and the Twelve Well Program (offered to Hoactzin and converted to a six well program upon the Company’s repurchase of the obligation to drill the last six wells as described above). The participants will continue to receive the agreed upon revenues allocable to their working interest until payout under the program occurs, when the Company will begin to receive a management fee of 85% of those working interest proceeds for the remaining life of the wells.

As of June 30, 2006 the Company completed a total reworking of its balance sheets that had been ongoing since February 2004. The Company has resolved all major litigation and eliminated the accompanying legal fees. The Company’s successful rights offering in February 2004 raised capital to pay off substantial debt. The Company also sold its small block of gas properties in Kansas obtaining a dollar benefit of high gas prices reflected in the $2.4 million sales price while simultaneously eliminating the high operating expenses of those properties. The Company used proceeds of the gas property sale to further pay down debt. The Company has also met its obligations to all of its preferred

stockholders by exchange their preferred stock either for cash, stock, or drilling program interests, and has accordingly cancelled all of the Series A, B, and C preferred stock. The Company has completed all of its drilling program obligations out of its own cash flow from operations and without additional borrowing for drilling. The Company continues to successfully rework existing wells and to drill new oil wells in Kansas and is acquiring additional lease acreage to increase production and to grow its reserves through the drill bit. During this time the Company has benefited from the currently high commodity prices for oil and gas and has used higher prices and increasing production volumes to conservatively fuel the reworking of the balance sheets and to prepare the Company for those times in the future when commodity prices may not be as favorable, which is a part of the business cycle that is well known and almost universally expected to some degree as an element of the oil and gas industry. The Company’s success in turning around its financial condition has enabled the Company to close the senior credit facility with Citibank Texas, N.A. in June 2006, thus meeting a primary Company goal to establish a commercial banking relationship with an established energy lender that will serve the Company as it continues to grow. In less than two years the Company has gone from total liabilities as of December 31, 2003 of about $19.4 million to approximately $4.4 million as of September 30, 2006, which includes the loan obligation to Citibank Texas. Management believes that the Company is now entering into a new period of development and growth.

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.

Revenue Recognition

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’ locations and usage is billed each month. Crude oil is stored and at the time of delivery to the purchasers, revenues are recognized.

Full Cost Method of Accounting

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

The Company’s proved oil and gas reserves as at December 31, 2005 were estimated by Ryder Scott, L.P., Petroleum Consultants. 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 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.

ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

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 $40.73 per barrel to a high of $64.00 per barrel during 2005. Gas price realizations ranged from a monthly low of $5.02 per Mcf to a monthly high of $14.03 per Mcf during the same period. The Company did not enter into any hedging agreements in 2005 or in 2006 to limit exposure to oil and gas price fluctuations.

Interest Rate Risk

On September 30, 2006, the Company had debt outstanding of approximately $169,000 at a fixed rate and $2,600,000 at a variable rate. The Company did not have any open derivative contracts relating to interest rates on September 30, 2006.

Forward-Looking Statements and Risk

Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company’s control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict.

There are numerous uncertainties inherent in estimating quantities of oil and gas reserves and 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 reserves and production estimates. The drilling of exploratory or developmental 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 4

CONTROLS AND PROCEDURES

Controls and Procedures

The Company maintains disclosure controls and procedures that are designed to ensure that information required to be disclosed by the Company in reports that it files or submits under the Securities Exchange Act, is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and that such information is accumulated and communicated to our management, including the Company's Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosures. In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives, and management necessarily is required to apply its judgment in evaluating the cost-benefit relationship of possible controls and procedures. As of the end of the period covered by this Report, and under the supervision and with the participation of the management, including its Chief Executive Officer and Chief Financial Officer, management evaluated the effectiveness of the design and operation of these disclosure controls and procedures. Based on this evaluation and subject to the foregoing, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company's disclosure controls and procedures were effective in reaching a reasonable level of assurance of achieving management’s desired controls and procedures objectives.

Changes in Internal Controls

During the period covered by this Report, there have not been any changes in the Company’s internal controls that have materially affected or are reasonably likely to materially affect the Company’s internal controls over financial reporting.

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

PART II OTHER INFORMATION

ITEM 2 UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

During the third quarter of fiscal 2006, the Company issued 1,396 unregistered and restricted shares of its common stock pursuant to the exercise of warrants issued by the Company to members of the plaintiff class as part of the settlement of the action entitled Paul Miller v. M. E. Ratliff and Tengasco, Inc.,

United States District Court for the Eastern District of Tennessee, Knoxville, Docket Number 3:02-CV-644. Those warrants are exercisable for a period of three years from date of issue at $0.45 per share and the warrants themselves are exempt from registration pursuant to Section 3(a) (10) of the Securities Act of 1933.

During the third quarter of fiscal 2006, the Company issued 20,000 registered and unrestricted shares upon the exercise of options granted under the Tengasco, Inc. Incentive Stock Plan.

ITEM 5

OTHER INFORMATION

The Company’s total oil production volume in Kansas for the third quarter of 45,550 barrels was record high quarterly production since the Company was founded in 1995. Third quarter oil production also included record single monthly production in each of the three months of the quarter compared to the same month in previous years. The Company spent $1.91 million for capital development in the third quarter of 2006 which includes costs of drilling, leasing and seismic exploration in Kansas.

The Company has completed drilling all of the wells in its 8 well program and expects that in early 2007, the participants in that program will have been paid back their investments which will result in the Company receiving an 85% management fee out of the participants’ working interests in those wells. The Company anticipates that the management fee would be approximately $600,000 per year if both production rates and commodity prices were to continue at current levels.

As a result of the Company having completed drilling all of its program wells, the third quarter of 2006 began with the Company drilling wells in which the working interest is owned exclusively by the Company. The Company also expects to have a 100% working interest in wells drilled in the future. Four such wells were drilled in the third quarter and to date, and all four wells resulted in commercial production of oil. The Crofoot C#6 was completed July 26, 2006 and has produced 1129 barrels to date, a 10 barrel per day average. The Dirks #1 was completed August 29, 2006 and has produced 2,624 barrels, a 26 barrel per day average. The Foster C #1 was completed on October 12, 2006 and has produced 739 barrels of oil, a 17 barrel per day average. The Crofoot A#10 was completed last week and has produced 578 barrels, a 75 barrel per day average but this initial production figure may change as production levels stabilize from this well.

The Company plans to continue drilling at a similar pace in 2007 as third party drilling rigs become available in Kansas. Depending on commodity prices, the Company expects to drill up to 18 wells in Kansas during 2007. The locations for these wells will be selected from the Company’s existing inventory of locations, some offsetting existing production, and others determined from the results of analysis of three dimensional seismic exploration that have proven

reliable in predicting locations for commercial wells.

Due to the Company’s focus on drilling and exploration in Kansas the Company has acquired an additional 17,060 acres of leased property in Kansas since late 2005. All of these prospects have encouraging geological signs and the Company expects these properties to provide potentially productive drilling targets for the future when 3-D seismic data is acquired and processed during the remainder of 2006 and in early 2007. Seismic data was obtained on the 3,800 acres that the Company leased in the second quarter 2006 in Trego County, KS and processing results are expected to be received by year end 2006. The Webster lease, a lease acquisition taking place during the early third quarter 2006, underwent a 3-D seismic shoot in October 2006 on its 2,800 acres and the resulting data should be processed early in the first quarter 2007. Seismic data is currently being acquired on a third Kansas prospect, the Plainville project. In October, 2006 the Company acquired one of its largest contiguous lease blocks to date, currently containing approximately 5,940 acres. Seismic data acquisition is expected to commence on this block in the first quarter of 2007.

On October 24, 2006 the Company signed a twenty-year Landfill Gas Sale and Purchase Agreement with BFI Waste Systems of Tennessee, LLC whereby the Company will buy the naturally produced gas stream presently being collected and flared at a municipal solid waste landfill serving the metropolitan area of Kingsport, Tennessee that is owned and operated by BFI in Church Hill, Tennessee. The landfill is located about two miles from the Company’s existing pipeline serving Eastman Chemical Company. 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 landfill gas stream to be purchased. 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 Chemical Company under the Company’s existing natural gas sales agreement.

The Company expects to arrange suitable project financing for the production of gas from this non-conventional source. Total costs for the project are expected to be approximately $3.7 million, and commercial operations are expected to begin about eight months from closing of financing. Assuming financing is obtained in the next sixty days, the Company estimates that commercial operations of the Project may begin as early as late summer or early fall of 2007. At current gas production rates and expected extraction efficiencies, when commercial operations of the Project begin, the Company would expect to deliver about 418 MMBtu per day of additional gas to Eastman, which would almost double the current volumes of natural gas being delivered to Eastman by the Company from the 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 BFI to occur between the years 2022 and 2026.

ITEM 6

EXHIBITS

(a)

The following exhibits are filed with this report:

31.1 Certification of the Chief Executive Officer, pursuant to Exchange Act Rule, Rule 13a-14a/15d-14a.

31.2 Certification of Chief Financial Officer, pursuant Exchange Act Rule, Rule 13a-14a/15d-14.

32.1 Certification of the 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.

SIGNATURES

Pursuant to the requirements of the Securities and Exchange Act of 1934, the Registrant duly caused this report to be signed on its behalf by the undersigned hereto duly authorized.

Dated: November 13, 2006

TENGASCO, INC.

By: s/ Jeffrey R. Bailey

Jeffrey R. Bailey

Chief Executive Officer

By: s/ Mark A. Ruth

Mark A. Ruth

Chief Financial Officer

Exhibit 31.1

CERTIFICATION

I, Jeffrey R. Bailey

1. I have reviewed this Quarterly Report on Form 10-Q of Tengasco, Inc. for the quarter ended September 30, 2006.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

4. The Registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules (13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made know to us by others within those entities, particularly during the period in which this report is being prepared:

(b) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation, and;

(c) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The Registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the Registrant’s board of directors (or persons performing the equivalent functions);

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the Registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Dated: November 13, 2006

By: s/ Jeffrey R. Bailey

Jeffrey R. Bailey

Chief Executive Officer

Exhibit 31.2

CERTIFICATION

I, Mark A. Ruth, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Tengasco, Inc. for the quarter ended September 30, 2006.

3. Based on my knowledge, the financial statements, and other information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this report;

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal control over financial reporting.

Dated: November 13, 2006

By: s/ Mark A. Ruth

Mark A. Ruth

Chief Financial Officer

Exhibit 32.1

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I hereby certify that:

I have reviewed the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006.

To the best of my knowledge this Quarterly Report on Form 10-Q (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities and Exchange Act of 1934 (15 U.S.C. 78m (a) or 78o (d)); and, (ii) the information contained in this Report fairly present, in all material respects, the financial condition and results of operations of Tengasco, Inc. and its subsidiaries during the period covered by this report.

Dated: November 13, 2006

By: s/Jeffrey R. Bailey
Jeffrey R. Bailey
Chief Executive Officer

Exhibit 32.2

CERTIFICATION

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 I hereby certify that:

I have reviewed the Quarterly Report on Form 10-Q for the quarter ended September 30, 2006.

Dated: November 13, 2006

By: s/Mark A. Ruth

Mark A. Ruth
Chief Financial Officer