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 June 30, 2007
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, 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.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Check One:
Large accelerated filer_____
Accelerated filer_______
Non-accelerated filer X
Indicate by check mark whether the registrant is a shell company (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: 59,138,705 common shares at July 31, 2007.
TENGASCO, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
PART I.
FINANCIAL INFORMATION
PAGE
ITEM 1. FINANCIAL STATEMENTS
* Condensed Consolidated Balance Sheets as of June 30, 2007 and December 31, 2006
3-4
* Condensed Consolidated Statements of Operations for the three and six months ended June 30, 2007and 2006
5
* Condensed Consolidated Statement of Stockholders’ Equity for the six months ended June 30, 2007
6
* Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2007 and 2006
7
* Notes to Condensed Consolidated Financial Statements
8-13
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
14-17
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
18
ITEM 4. CONTROLS AND PROCEDURES
19
PART II.
OTHER INFORMATION
ITEM 2. UNREGISTERD SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ITEM 4 SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
20
ITEM 5. OTHER INFORMATION
ITEM 6. EXHIBITS
21
* SIGNATURES
22
* CERTIFICATIONS
23-26
CONDENSED CONSOLIDATED BALANCE SHEETS
ASSETS
June 30, 2007
(Unaudited)
December 31, 2006
Assets
Current
Cash and cash equivalents
$ 443,659
$ 369,665
Accounts receivable
972,639
719,840
Participant receivables
16,594
13,008
Inventory
581,138
550,522
Other current assets
11,056
Total current assets
2,025,086
1,664,091
Restricted Cash
120,500
Loan Fees
193,752
237,738
Oil and gas properties, net (on the basis
of full cost accounting)
13,585,113
12,703,629
Pipeline facilities, net
13,188,667
13,460,667
Other property and equipment, net
281,081
267,713
$ 29,394,199
$ 28,454,338
See accompanying notes to condensed consolidated financial statements
3
LIABILITIES AND STOCKHOLDERS’ EQUITY
June 30, 2007 (Unaudited)
Current liabilities
Current maturities of long-term debt
$
71,892
65,267
Accounts payable
577,990
687,475
Accrued interest payable
-
8,432
Other accrued liabilities
114,550
30,410
Total current liabilities
764,432
791,584
Asset retirement obligation
541,574
512,015
Long term debt, less current maturities
3,445,962
2,730,534
Total liabilities
4,751,968
4,034,133
Stockholders’ equity
Common stock, $.001 par value; authorized 100,000,000 shares; 59,138,705 and 59,003,284 shares issued and outstanding
59,139
59,004
Additional paid-in capital
54,617,633
54,517,333
Accumulated deficit
(30,034,541)
(30,156,132
)
Total stockholders’ equity
24,642,231
24,420,205
29,394,199
28,454,338
4
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Three Months Ended June 30,
For the Six Months Ended June 30,
2007
2006
Revenues and other income
Oil and gas revenues
$ 2,194,923
$ 2,328,275
$ 3,944,694
$ 4,404,417
Pipeline transportation revenues
20,774
22,700
40,182
45,491
Interest income
4,742
3,761
7,963
3,797
Total revenues and other income
2,220,439
2,354,736
3,992,839
4,453,705
Cost and other deductions
Production costs and taxes
948,976
811,342
1,912,106
1,666,852
Depletion, depreciation and amortization
467,303
405,893
943,354
811,779
Interest expense
80,569
26,948
151,592
49,037
General and administrative cost
351,908
339,621
697,496
737,846
Public relations
17,947
22,369
18,341
24,081
Professional fees
22,980
27,794
148,359
126,994
Total cost and other deductions
1,889,683
1,633,967
3,871,248
3,416,589
Net Income
$ 330,756
$ 720,769
$ 121,591
$ 1,037,116
Net Income per share
Basic and diluted:
Operations
$ 0.01
$ 0.00
$ 0.02
Total
Shares used in computing Earnings Per Share
Basic
59,128,705
58,823,714
59,089,117
58,715,015
Diluted
60,950,428
60,249,141
60,910,840
60,140,442
CONDENSED CONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY
Common Stock
Shares
Amount
Additional Paid in Capital
Accumulated Deficit
Balance at December 31, 2006
59,003,284
$ 59,004
$ 54,517,333
$ (30,156,132)
$ 24,420,205
121,591
Options & Compensation Expense
135,250
135
100,223
100,358
Common Stock Issued for Exercise of Warrants
171
77
Balance June 30, 2007 (Unaudited)
59,138,705
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For the Six Months Ended June 30, 2007
For the Six Months Ended June 30, 2006
Operating activities
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization
Accretion on Asset Retirement Obligation
31,302
34,386
(Gain)/Loss on sale of vehicles/equipment
5,740
(22,565)
Compensation and services paid in stock options
50,438
80,780
Changes in assets and liabilities:
(252,799)
55,495
(3,586)
(18,597)
(5,000)
(30,616)
(7,762)
(109,485)
51,800
(8,432)
84,140
97,414
Settlement on Asset Retirement Obligation
(1,743)
(28,889)
Net cash provided by operating activities
829,904
2,085,957
Investing activities
Additions to other property & equipment
(96,476)
(59,239)
Restricted cash
(120,500)
Decrease to other property & equipment
27,915
Net additions to oil and gas properties
(1,431,484)
(1,956,604)
Drilling Program portion of additional drilling
1,067,400
Increase/decrease in pipeline facilities
(250)
Net cash (used in) investing activities
(1,527,960)
(1,041,278)
Financing activities
Proceeds from borrowings
787,236
1,452,783
Repayments of borrowings
(65,183)
(71,863)
(236,651)
Decrease in Drilling Program liability
(2,324,400)
Proceeds from exercise of warrants & options
49,997
142,179
Net cash provided by (used in) financing activities
772,050
(1,037,952)
Net change in cash and cash equivalents
73,994
6,727
Cash and cash equivalents, beginning of period
369,665
260,969
Cash and cash equivalents, end of period
443,659
$ 267,696
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(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 six months ended June 30, 2007 are not necessarily indicative of the results that may be expected for the year ended December 31, 2007. No income tax expense was recognized for the six months ended June 30, 2007 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 six months ending June 30, 2007 and 2006, management reserved the gross tax benefit. 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, 2006.
(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 59,128,705 and 58,823,714 weighted average shares outstanding for the quarters ended June 30, 2007 and June 30, 2006 respectively and 59,089,117 and 58,715,015 for the six months ended June 30, 2007 and June 30, 2006 respectively. Diluted earnings per common share is 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.
Dilutive shares outstanding at June 30, 2007 were 1,821,723, related to outstanding options and warrants and 1,425,427 for June 30, 2006.
8
(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 are now recorded as expense over the vesting period of the award based on their fair values at the date the stock based compensation is granted. The cumulative effect of initially applying SFAS 123(R) was recognized as of the required effective date using a modified prospective method. Under the modified prospective method the Company has 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 $50,438 in compensation expense in the first six months of 2007 for options granted and $80,780 in 2006. The Company will recognize $100,878 in 2007 and 2008 in compensation expense relating to these options granted. The ultimate impact on results of operation and financial position in future years will depend upon the level of stock-based compensation granted.
In July 2006, the FASB issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement 109" ("FIN 48"), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is "more-likely-than-not" to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the "more-likely-than-not" threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, we adopted FIN 48 on January 1, 2007. We do not
9
expect the interpretation will have a material impact on our results of operations or financial position.
In September 2006, the Securities and Exchange Commission staff published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The Company adopted SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. It defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurement. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. It clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company continues to evaluate the impact the adoption of this statement could have on its financial condition, results of operations and cash flows.
In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — Including an Amendment of FASB 115” (“SFAS 159”). SFAS 159 permits entities to elect to report eligible financial instruments at fair value subject to conditions stated in the pronouncement including adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial reporting by mitigating volatility in earnings related to current reporting requirements. The Company is considering the applicability of SFAS 159 and will determine if adoption is appropriate. The effective date for SFAS 159 is for fiscal years beginning after November 15, 2007. The Company believes that adopting SFAS 159 will not result in any material effect on its financial position or operating results.
10
(4)
Related Party Transactions
On October 5, 2005, Hoactzin Partners, L.P. ("Hoactzin") surrendered to the Company two outstanding promissory notes dated May 19, 2005 and August 22, 2005 made by the Company to Dolphin Offshore Partners. L.P. (“Dolphin”) in the aggregate principal amount of $2,514,000. Peter E. Salas who is Chairman of the Company’s Board of Directors is the sole shareholder and controlling person of Dolphin Management Inc., the general partner of Dolphin. Mr. Salas is also the controlling person of Hoactzin. In exchange for the surrender of these notes, the Company entered into an agreement granting Hoactzin a 94.3% working interest in a 12-well drilling program to be undertaken by the Company on its properties in Kansas. The Company retained 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. 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 then outstanding 12-well Kansas drilling program.
If the Company had not exercised its repurchase option, Hoactzin would have received a 94% working interest in the final six wells of the program until payout as established under 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. Hoactzin will continue to receive its agreed upon revenues allocable to its working interest until payout under the program occurs, at which time the Company will begin to receive a management fee of 85% of Hoatzin’s working interest proceeds for the remaining life of the six program wells.
(5)
Oil and Gas Properties
The following table sets forth information concerning the Company’s oil and gas properties
Oil and gas properties, at cost
$ 19,883,217
$ 18,745,834
Unevaluated properties
2,174,912
1,880,811
Accumulation depreciation,
depletion and amortization
(8,473,016)
(7,923,016)
Oil and gas properties, net
$ 13,585,113
$ 12,703,629
11
The Company recorded $550,000 in depletion expense for the first six months of 2007 and $450,000 in the first six months of 2006.
(6)
Asset Retirement Obligation
The Company follows the requirements of SFAS 143. Among other things, SFAS 143 requires entities to record a liability and corresponding increase in long-lived assets for the present value of material obligations associated with the retirement of tangible long-lived assets. Over the passage of time, accretion of the liability is recognized as an operating expense and the capitalized cost is depleted over the estimated useful life of the related asset. Additionally, SFAS 143 required that upon initial application of these standards, the Company recognized a cumulative effect of a change in accounting principle corresponding to the accumulated accretion and depletion expense that would have been recognized had this standard been applied at the time the long-lived assets were acquired or constructed. The Company’s asset retirement obligations relate primarily to the plugging, dismantling and removal of wells drilled to date. The Company’s calculation of Asset Retirement Obligation used a credit-adjusted risk free rate of 12%, an estimated useful life of wells ranging from 30-40 years, estimated plugging and abandonment costs range from $5,000 per well to $10,000 per well. Management continues to periodically evaluate the appropriateness of these assumptions.
(7)
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.
(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.
12
The facility has standard loan covenants such as current ratios, and interest coverage ratios, etc., with which the Company is in compliance. $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 closing costs consisting of legal fees, mortgage taxes, commissions and bank fees in connection with the Citibank facility of $285,224 in 2006. This amount will be amortized over the term of the Citibank note.
On April 19, 2007 the Company borrowed the additional sum of $700,000 from Citibank, N.A. under its existing revolving credit facility dated June 29, 2006. The additional borrowing resulted from an increase in the Company’s borrowing base under the Citibank credit facility from $2.6 million to $3.3 million based upon Citibank’s periodic review of the Company’s borrowing base. With the additional borrowing, the Company has borrowed the full amount of its $3.3 million borrowing base under the revolving Citibank credit facility. Repayment of this additional sum is subject to the terms and conditions of the Citibank credit facility. The additional amount borrowed will be used for further development of the Company’s producing properties.
ITEM 2 MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations and Financial Condition
Kansas
During the first six months of 2007, the Company sold 89,887 gross barrels of oil from its Kansas Properties comprised of 143 producing oil wells. Of the 89,887 gross barrels, 63,003 barrels were net to the Company after required payments to all of the Drilling Program participants and royalty interests. The Company’s sales for the first six months of 2007 of 63,003 net barrels of oil compares to 59,018 barrels sold to the Company’s interest in the first six months of 2006. The Company’s net revenues from the Kansas properties were $3,518,744 in the first six months of 2007 compared to $3,654,420 in 2006. This decrease was due to decrease in prices for oil from an average of $61.92 in 2006 to an average of $55.85 in 2007 resulting in a decrease in revenues of approximately $355,000. This was partially offset by the increase in volume of approximately $220,000. The Company’s production was affected by inclement weather in Kansas in the first quarter of 2007.
Tennessee
During the first six months of 2007, the Company produced gas from 23 wells in the Swan Creek field, which it primarily sold in Kingsport, Tennessee to Eastman
13
Chemical Company. Natural gas production from the Swan Creek field for the first six months of 2007 was an average of 223 Mcf per day during that period as compared to 406 Mcf per day in the first six months of 2006. The first six months production reflected expected natural decline in production from the existing Swan Creek gas wells which were first brought into production in mid-2001 upon completion of the Company’s pipeline. For the first six months of 2007 the Company produced 3,813 barrels of oil as compared to 4,063 in the first six months of 2006.
Comparison of the Quarters Ended June 30, 2007 and 2006
The Company recognized $2,220,439 in revenues from its Kansas Properties and the Swan Creek field during the second quarter of 2007 compared to $2,354,736 in the second quarter of 2006. The decrease in revenues was due to a decrease in oil prices in 2007 and a 16,679 mcf net decrease in gas sales. Oil prices in the second quarter of 2007 averaged $59.08 per barrel as compared to $64.92 per barrel in the second quarter of 2006. The Company realized a net income attributable to common shareholders of $330,756 or $0.01 per share of common stock during the second quarter of 2007, compared to a net income in the second quarter of 2006 to common shareholders of $720,769 or $0.01 per share of common stock.
Production costs and taxes in the second quarter of 2007 increased to $948,976 from $811,342 in the second quarter of 2006. The difference is due to increased workovers to increase production, increased taxes, and overall cost increases of supplies in the industry.
Depreciation, depletion, and amortization expense for the second quarter of 2007 was $467,303 compared to $405,893 in the second quarter of 2006, the increase mainly relates to depletion taken on oil and gas properties.
During the second quarter of 2007, general and administrative costs increased slightly to $351,908 from $339,621 in the second quarter of 2006.
Professional fees in the second quarter of 2007 were $22,980 compared to $27,794 in the same period in 2006.
Interest expense for the second quarter of 2007 increased to $80,569 from $26,948 in the second quarter of 2006. The increase relates to the Citibank loan.
Comparison of the Six Months Ended June 30, 2007 and 2006
The Company recognized $3,992,839 in total revenues from its Kansas Properties and the Swan Creek Field during the first six months of 2007 compared to $4,453,705 in the first six months of 2006. The decrease in revenues was due to an decrease in oil prices in 2007 partially offset by Kansas oil sales increase during this period of 3,985 net bbls which is attributable to well workovers, polymer completion workovers and the Company’s portion of an eight-well drilling program. Oil prices in the first six months of
14
2007 averaged $55.85 per barrel as compared to $61.92 per barrel in the first six months of 2006.
The Company realized a net income attributable to common shareholders of $121,591 or $0.00 per share of common stock during the first six months of 2007, compared to a net income in the first six months of 2006 to common shareholders of $1,037,116 or $0.02 per share of common stock.
Production costs and taxes in the first six months of 2007 increased to $1,912,106 from $1,666,852 in the first six months of 2006. The difference is due to increased workovers to increase production, increased taxes, and overall cost increases of supplies in the industry.
Depletion, depreciation, and amortization expense for the first six months of 2007 was $943,354 compared to $811,779 in the first six months of 2006. The increase relates to depletion taken on Oil and Gas Properties.
During the first six months of 2007, general and administrative costs decreased slightly to $697,496 from $737,846.
Professional fees in the first six months of 2007 were $148,359 compared to $126,994 in the same period in 2006.
Interest expense for the first six months of 2007 increased to $151,592 from $49,037 in the first six months of 2006. The increase relates to the Citibank Loan.
Liquidity and Capital Resources
On June 29, 2006 the Company closed a $50,000,000 revolving senior credit facility between the Company and Citibank Texas, N.A. in its own capacity and also as agent for other banks. Under the facility, loans and letters of credit 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. On April 19, 2007 as a result of periodic review under the credit facility, the borrowing base was increased to $3.3 million, and the Company borrowed the additional amount of $700,000 which was used for development of the Company’s producing properties.
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
15
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’ location and usage is billed each month. Crude oil is stored and at the time of delivery to the customers, 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, day rate rentals and the costs of drilling, completing and equipping oil and gas wells. Costs, however, associated with production and general corporate activities are expensed in the period incurred. Interest costs related to unproved properties and properties under development are also capitalized to oil and gas properties. Gains or losses are recognized only upon sales or dispositions of significant amounts of oil and gas reserves representing an entire cost center. Proceeds from all other sales or dispositions are treated as reductions to capitalized costs. The capitalized oil and gas property, less accumulated depreciation, depletion and amortization and related deferred income taxes, if any, are generally limited to an amount (the ceiling limitation) equal to the sum of: (a) the present value of estimated future net revenues computed by applying current prices in effect as of the balance sheet date (with consideration of price changes only to the extent provided by contractual arrangements) to estimated future production of proved oil and gas reserves, less estimated future expenditures (based on current costs) to be incurred in developing and producing the reserves using a discount factor of 10% and assuming continuation of existing economic conditions; and (b) the cost of investments in unevaluated properties that are excluded from the costs being amortized. No ceiling write-downs were recorded in 2007 or 2006.
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.
16
The Company’s proved oil and gas reserves as of December 31, 2006 were determined by LaRoche Petroleum Consultants, Ltd. Projecting the effects of commodity prices on production, and timing of development expenditures includes many factors beyond the Company’s control.
The future estimates of net cash flows from the Company’s proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates.
Asset Retirement Obligations
The Company is required to record the effects of contractual or other legal obligations on well abandonments for capping and plugging wells. Management periodically reviews the estimate of the timing of the wells’ closure as well as the estimated closing costs, discounted at the credit adjusted risk free rate of 12%. Quarterly, management accretes the 12% discount into the liability and makes other adjustments to the liability for well retirements incurred during the period.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISKS
Commodity Risk
The Company's major market risk exposure is in the pricing applicable to its oil and gas production. Realized pricing is primarily driven by the prevailing worldwide price for crude oil and spot prices applicable to natural gas production. Historically, prices received for oil and gas production have been volatile and unpredictable and price volatility is expected to continue. Monthly oil price realizations ranged from a low of $51.74 per barrel to a high of $68.82 per barrel during 2006. Gas price realizations ranged from a monthly low of $4.20 per Mcf to a monthly high of $11.55 per Mcf during the same period. The Company did not enter into any hedging agreements in 2007 or 2006 to limit exposure to oil and gas price fluctuations.
Interest Rate Risk
At June 30, 2007, the Company had debt outstanding of $3,517,854 including, as of that date, $3,300,000 owed on its credit facility with Citibank Texas, N. A. The interest rate on the Citibank credit facility is variable at a rate equal to LIBOR plus 2.5%. The Company’s debt owed to other parties of $217,854 has fixed interest rates ranging from 5.5% to 8.25%. As a result, the Company's annual interest costs in 2006 fluctuated based on short-term interest rates on approximately 93% of its total debt outstanding at December 31, 2006. The impact on interest expense and the Company’s cash flows of a 10 percent increase in the interest rate on the Citibank Credit facility would be approximately $27,225. The Company did not have any open derivative contracts relating to interest rates at December 31, 2006 or June 30, 2007.
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Forward-Looking Statements and Risk
Certain statements in this report, including statements of the future plans, objectives, and expected performance of the Company, are forward-looking statements that are dependent upon certain events, risks and uncertainties that may be outside the Company's control, and which could cause actual results to differ materially from those anticipated. Some of these include, but are not limited to, the market prices of oil and gas, economic and competitive conditions, inflation rates, legislative and regulatory changes, financial market conditions, political and economic uncertainties of foreign governments, future business decisions, and other uncertainties, all of which are difficult to predict.
There are numerous uncertainties inherent in projecting future rates of production and the timing of development expenditures. The total amount or timing of actual future production may vary significantly from estimates. The drilling of exploratory wells can involve significant risks, including those related to timing, success rates and cost overruns. Lease and rig availability, complex geology and other factors can also affect these risks. Additionally, fluctuations in oil and gas prices, or a prolonged period of low prices, may substantially adversely affect the Company's financial position, results of operations, and cash flows.
ITEM 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 second quarter of 2007, the Company issued 80,000 registered and unrestricted shares upon the exercise of options granted under the Tengasco, Inc. Incentive Stock Plan.
(a) The annual meeting of stockholders of the Company was held on April 30, 2007.
(b) The first item voted upon was the election of Directors. Matthew K. Behrent, Jeffrey R. Bailey, John A. Clendening,, Carlos P. Salas, and Peter E. Salas were elected as Directors of the Company for a term of one year or until their successors are elected and qualified. The results of voting were as follows: 47,897,774 votes for Matthew K. Behrent and 121,546 withheld; 47,915,832 votes for Jeffrey R. Bailey and 103,488 withheld; 47,914,630 votes for John A. Clendening and 104,690 withheld; 47,676,327 votes for Carlos P. Salas and 342,993 withheld; and, 47,888,301 votes for Peter E. Salas and 131,019 withheld.
A majority of votes at the meeting having voted for them, Messrs. Matthew K. Behrent, Jeffrey R. Bailey, John A. Clendening, Carlos P. Salas, and Peter E. Salas were duly elected as Directors of the Company.
(c) The next item voted on was a proposal to ratify the appointment by the Audit Committee of the Board of Directors of Rodefer Moss & Co, PLLC to serve as the independent certified public accountants of the Company for fiscal 2007.The results of the voting were as follows:
47,905,277 votes for the proposal;
48,952 votes against; and
65,091 abstained.
A majority of the votes cast at the meeting having voted for the proposal, the proposal was duly passed.
No other matters were voted upon at the meeting.
ITEM 5 OTHER INFORMATION
During the second quarter of 2007 the Company drilled two wells on its leases in Kansas, the Lowry B No. 1 and Dirks No. 2. In addition, the Company drilled two other wells there in early July 2007, the Howard No.1 and Hobrock No.5. The Company has filed permits for drilling of two additional Kansas wells to be drilled in August 2007, the Gilliland and Veverka wells.
Results of these wells drilled to the date of this report are as follows:
LOWRY 'B' No. 1 (Webster): plugged & abandoned on May 22, 2007.
DIRKS #2 (Pawnee Rock): Finished drilling June 15, 2007. This well was completed and is currently producing approximately 12 barrels per day.
HOWARD 1 (Wildcat Trego County): Plugged and abandoned July 4, 2007.
HOBROCK 5 (Hobrock Extension): Drilled July 13, 2007. We anticipate this well will have commercial production; however we await the arrival of a completion rig to complete the well. The rig is scheduled for the week of August 6, 2007.
As of the date of this Report the Company’s subsidiary Manufactured Methane Corporation is in negotiations to conclude project financing for its Carter Valley, Tennessee extraction facility for production of methane gas from landfill gas under its agreement with Allied Waste. However, MMC has placed the equipment order with MEDAL, a joint venture between DuPont and Air Liquide, for its BIOGAZ system, which is the equipment requiring the longest lead time before delivery, in order to reduce delay of startup of operations. It is now anticipated that closing of project financing will occur in August 2007 and that required equipment would be delivered by year-end 2007, with production to begin in the first quarter of 2008 when installation, testing, and startup procedures are completed. As part of the project agreement, the Company has agreed to install a new force-main water drainage line for Allied Waste 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 line. Allied Waste will be responsible for the additional costs for the water line. Additional time for engineering studies relating to the wastewater line was needed by
Allied Waste to design its portion of the combined pipeline installation. Construction of the gas pipeline needed to connect the facility with the Company’s existing natural gas pipeline is expected to begin upon receipt of permits from Tennessee state and local wastewater authorities in connection with the drainage line. Those permit applications were submitted by Allied Waste in late July, 2007 and the Company expects the permits to be acted upon promptly. As a certificated utility, the Company’s pipeline subsidiary requires no additional permits for the gas pipeline construction.
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: August 10, 2007
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 June 30, 2007.
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 known 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.
Exhibit 31.2
I, Mark A. Ruth, certify that:
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)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;
By: s/ Mark A. Ruth
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Exhibit 32.1
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 June 30, 2007.
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 presents, in all material respects, the financial condition and results of operations of Tengasco, Inc. and its subsidiaries during the period covered by this report.
By: s/Jeffrey R. Bailey Jeffrey R. Bailey Chief Executive Officer
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Exhibit 32.2
By: s/Mark A. Ruth
Mark A. Ruth Chief Financial Officer
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