Thursday, May 08, 2008 8:44:03 PM
Table Pounde TGC...
TGC.... AMEX..
Home Page:http://www.tengasco.com/
Profile..
Tengasco, Inc. engages in the exploration, production, and transportation of oil and natural gas in Kansas and Tennessee. The company also leases producing and non-producing properties, as well as owns pipeline and other infrastructure facilities to provide transportation services. It owns interests in 143 producing oil wells in the vicinity of Hays, Kansas; and 23 natural gas wells in the Swan Creek Field, Tennessee. The company markets its crude oil to refining companies, utilities, and private industry end-users; and natural gas to utilities, private industry end-users, and natural gas marketing companies. Tengasco was founded as Gold Deposit Mining & Milling Company in 1916 and changed its name to Onasco Companies, Inc. Further, it changed its name to Tengasco, Inc. in 1995. The company is based in Knoxville, Tennessee.
Yahoo Key Statistics: http://finance.yahoo.com/q/ks?s=TGC
Press Releases: http://www.tengasco.com/press_releases.shtml
Press Releases: http://finance.yahoo.com/q?s=TGC
Latest Qtr. report:
http://investorshub.advfn.com/boards/read_msg.asp?message_id=29079706
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My back of the napkin thoughts..
Net cash provided from operation were..
2005... $2,113,000
2006... $4,353,000
2007... $3,446,000 2007 includes 1,200,000 in expenses for work over of wells..
Reserves went from $26,627.00 in 2006 to $53,627,000 to $53,627,000 in 2007..
Net income:
2005 $1,088,000
2006 $2,141,000
2007 $1,410,000 + $2,100.00 from a tax credit.. Wells in Kansas where shut down in 2007 for an extended period due to ice conditions and the loss of electric power.. No damage was created to any equipment or wells..
Average Oil prices: Oil is purchased at wellhead by a gathering company at current price postings less 4% and payments are current for such sales..
2006 Average price recieved..$60.84
2007 Average price recieved..$66.42
**Gas prices received for sales of gas from the Swan Creek Field averaged $6.86 per Mcf in 2007, $7.27 per Mcf in 2006 and $8.74 per Mcf in 2005. Oil prices received for sales of oil from the Swan Creek field averaged $64.81 per barrel in 2007, and $60.39 per barrel in 2006, and. $53.90 per barrel in 2005.
***The Company realized revenues of $9,368,624 in 2007 compared to $9,001,681 in 2006 and compared to $7,172,876 in 2005. Revenues increased $366,943 from 2006 due primarily to an increase in oil prices in Kansas;
2007 Sales and earnings adjustments for 2008..
$9,368,624.00 revenues in 2007..
Earnings before Tax credits...2007 $1,410,000...
Add $800,000.00 in non recurring work over wells maintainence..
Add $1,200,000 in increased production from well programs..
Add $150.000 pickup for storm shutdowns..
Add $80,000 for increased Ngas prices recieved...
Total: $2,230,000 X .66 To account for taxes and Depletion = $1,471,000...
Total Earnings in 2008 should be at $66.42 with an oil Ave. of..$2,881,000Earnings added after after taxes and depletion.. after (T&D)$0.487 PS..
Oil @$79.70 Add $1,236,000 after (T&D) $4,117,000 $0.0696 PS
Oil @$86.34 Add $1,854,000 after (T&D) $4,735,000 $0.0800 PS
Oil @$92.98 Add $2,497,000 after (T&D} $5,378,000 $0.0909 PS
Oil @$99.63 Add $3,091,000 after (T&D) $5,972,000 $0.1010 PS
Oil @$106.00 Add $3,709,000 after (T&D) $6,590,000 $0.1114 PS
Oil @$112.91 Add $4,327,000 after (T&D) $7,208,000 $0.1218 PS
Oil @$119.55 Add $4,946,000 after (T&D) $7,827,000 $0.1323 PS
The earnings per share above only include existing production and do not include any further development on owned properites and leases that are presently being conducted.. EPS include all taxes and decline rates taken into consideraton when making asumptions.. I am long as My trading accounts indicates.. hank
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Reserves:
KNOXVILLE, TN--(MARKET WIRE)--Feb 6, 2008 -- Tengasco, Inc. (AMEX:TGC - News) announced today that the Company's total proved reserves at December 31, 2007 have more than doubled in value from year-end 2006. The reserve report prepared by the independent engineering firm of LaRoche Petroleum Consultants, Ltd. of Houston, Texas indicates that the value of the Company's total proved oil and gas reserves as of December 31, 2007 calculated at a net present value using a 10% discount factor was $53,627,086, up from the 2006 year-end total of $26,469,192. The LaRoche reserve report indicates that the value of the oil and gas reserves attributable to the Company's ownership interests :http://biz.yahoo.com/iw/080206/0358367.html
2007 Results of Operations:
TGC incurred a net income to holders of common stock of $3,510,322 or $0.06 per share in 2007 compared to a net income of $2,141,364 or $0.04 per share in 2006 and compared to a net income of $1,088,028 or $0.02 per share in 2005. The Company recognized a tax benefit for net operating loss carry forwards in the amount of $2,100,000 in 2007.
The Company realized revenues of $9,368,624 in 2007 compared to $9,001,681 in 2006 and compared to $7,172,876 in 2005. Revenues increased $366,943 from 2006 due primarily to an increase in oil prices in Kansas; prices averaged $66.42 in 2007 and 60.84 in 2006. Gross oil production in 2007 was just slightly less than 2006 resulting from the loss of production in January 2007 due to the electricity outage during an ice storm.
As a result of that storm, many counties in Kansas, including some counties where the Company has wells, lost power for the entire month of January. Producing wells in those counties were unable to produce without electricity to run the well pumps during the power outage. Consequently in January 2007 the Company saw production and revenue decline from monthly levels in late 2006. None of the Company’s producing wells were physically damaged by the ice storm or by non production during the absence of power, but the storm did substantially adversely impact production levels and sales in the first two months of 2007 while at the same time causing an increase in expenses. Eventually new poles and lines were rebuilt on a locally massive scale and electrical power was restored, and the Company experienced a rebound of production commencing in March 2007.
In 2007, the Company continued to focus its exploration and drilling activities in Kansas.
In 2007, the Company drilled 16 new wells on its Kansas Properties, of which 9 wells were under the ten well program discussed below in greater detail. Of these new wells, 10 are producing commercial quantities of oil. These new wells are producing approximately 135 barrels of oil per day.
The Company also continued in 2007 its program of work-overs of existing wells to increase production. The Company’s focus in 2007 on its Kansas oil production and the results achieved by the Company from its ongoing operations, drilling and work-overs are having a positive impact on the Company’s reserves resulting in the Company’s total proved reserves at December 31, 2007 having more than doubled in value from year-end 2006. Fifty-Six (56%) percent of that increase in reserve growth is attributable to the Company’s ongoing operational activities and the new Proved Undeveloped (PUD) future drilling locations that the Company has established as a result of these successes. See, Item 2, “Properties” – “Reserve Analysis” for a more detailed discussion of the Company’s reserves.
During 2007, the Company also continued its lease acquisition program in Kansas to acquire oil and gas leases in areas near its previous lease holdings where the Company believes there is a likelihood of additional oil production. The Company continued to collect and analyze substantial seismic data to aid it in its drilling operations. The Company intends in 2008 to continue to acquire additional leases in the area of its existing wells.
Production.....
Kansas Properties...
The Kansas Properties as of December 31, 2007 contained 192 leases totaling 28,934 acres in the vicinity of Hays, Kansas. The increase in the total volume of acreage of the Company’s Kansas Properties from 27,837 acres at the end of 2006 is primarily due to the purchase of two producing leases, the Heyl and RJ Thyfault. The Company focused its drilling, development, and exploration activities in Kansas in 2007 on evaluation of older producing properties, and those properties acquired in 2005 and 2006. Many of these leases, however, are still in effect because they are being held by production. The leases provide for a landowner royalty of 12.5%. Some wells are subject to an overriding royalty interest from 0.5% to 9%. The Company maintains a 100% working interest in most of its older wells and any undrilled acreage in Kansas. The terms for most of the Company’s newer leases in Kansas are from three to five years.
Kansas as a whole is of major significance to the Company. The majority of the Company’s current reserve value, current production, revenue, and future development objectives are centered in the Company’s ongoing interests in Kansas. By using 3-D seismic evaluation on existing locations owned by the Company in Kansas, the Company has added and continues to add proven direct offset locations. As a result of recent higher commodity prices for its oil, the Company has been able to drill from cash flow and attract favorable drilling partner programs in which the Company retains not only a carried beginning interest but a higher-than-industry-standard reversionary interest. The Company expects to continue this mix of company drilling and program drilling depending primarily on future cash flow and future oil prices. Breaking down the Company’s assets in Kansas into individual leases produces no apparent stand out leases that appear to be stand-alone principal properties. As a whole, however, our collective central Kansas holdings (see map below) are of major significance and as a group the most materially important segment of the Company as demonstrated by the following facts during the year ending December 31, 2007:
• Kansas accounted for 91.4% of the Company’s revenue (i.e. $8,560,097 of $9,368,624.)
• Kansas accounted for 86% of the Company’s total production measured in BOE (Barrel of Oil Equivalent)
• Kansas contributes $14.791 million in value of future proven development locations as of year end 2007, compared to just $567,000 in Tennessee
• The Company’s focus in 2008 will be to continue with offset seismic development, and leasing activity in Kansas. As a result, the Company’s undeveloped location value and total number of locations are expected to grow.
In 2007 the Company produced 178,311 barrels of oil in Kansas compared to 179,555 in 2006, a decrease of 1,244 barrels for the year. Additionally, the wells in the Eight Well Program (former Series “A”) reached the reversionary “flip point” in April 2007. This is the point at which the Company started receiving 85% of the participant’s interest plus our original interest of (19.3%) for an approximate total net interest to the Company equal to an 88% interest. In 2007 those wells produced 22,195 gross barrels of oil; the wells in the Twelve Well Program (former Series “B”) now converted to a six well program produced 15,864 gross barrels; wells polymered produced 19,502 barrels; and, the two new wells drilled produced 2,566 gross barrels in 2007.
During 2007 the Company drilled 9 of the 10 wells in the Ten Well Program and produced 3,649 barrels from the 5 wells that were completed by year-end. The other three wells that were drilled in 2007 were then completed in 2008. In March 2008, the tenth and final well in the Ten Well Program was both drilled and completed as a producer. As of the date of this report, nine of ten wells drilled in the Ten Well Program have been completed as producers and are producing approximately 106 barrels per day. During the first half of 2008 the Company expects the reversionary flip point for the Twelve Well Program (former Series “B”) now converted to a six well program, to be achieved.
Gas prices received for sales of gas from the Swan Creek Field averaged $6.86 per Mcf in 2007, $7.27 per Mcf in 2006 and $8.74 per Mcf in 2005. Oil prices received for sales of oil from the Swan Creek field averaged $64.81 per barrel in 2007, and $60.39 per barrel in 2006, and. $53.90 per barrel in 2005.
Production costs and taxes in 2007 increased to $4,322,833 from $3,287,233 in 2006 and $3,046,460 in 2005. The difference is due to increased work-overs to increase production, increased taxes, and overall cost increases of supplies in the industry.
Depletion, depreciation, and amortization for 2007 was $1,631,468, a decrease from $1,911,416 in 2006 due to production volumes added to future reserves from drilling activities. Depletion, depreciation, and amortization increased to $1,911,416 in 2006 from $1,605,043 in 2005. The increase in 2006 was due to a change in focus by the Company toward drilling in Kansas rather than in Tennessee, therefore removing drilling and development locations in Tennessee.
The Company’s general and administrative costs of $1,417,001 in 2007 remained generally consistent with 2006 levels of $1,293,109 and 2005 levels of $1,322,616. The 2007, 2006 and 2005 costs included non-cash charges related to stock options of $116,476, $159,160 and $103,400 respectively.
The increase in interest expense in 2007 relates to the borrowing base increase of the Citibank credit facility in 2007. Interest expense for 2006 decreased significantly over 2005 levels. This was due to the conversion of the Company’s preferred stock, which was subject to mandatory redemption, into either interest in a drilling program, common stock or cash payoffs. As of December 31, 2006, the Company’s only debt financing were vehicle loans totaling $195,801 and the CitiBank loan of $2,600,000.
The Company’s public relations costs remained stable at $21,605 for 2007, compared to $26,037 for 2006 and $30,020 for 2005 as the Company continued to apply cost saving methods in the preparation of its annual report and in publishing of press releases.
Professional fees in 2007 were $232,197 compared to $173,932 in 2006. This was due to the Company commencing its review of its internal controls over its financial reporting in accordance with Item 308(T) of Regulation S-K. Professional fees in 2006 decreased from 2005 levels as the Company’s litigation was settled.
The Company recorded a deferred tax asset of $2,100,000 in 2007 relating to the Company’s net operating loss carry forwards. The Company recorded a gain on disposal of preferred stock of $655,746 in 2005.
Liquidity and Capital Resources .....
On June 29, 2006, the Company closed a $50,000,000 revolving senior credit facility between the Company and Citibank Texas, N.A. in its own capacity and also as agent for other banks. Under the facility, loans and letters of credit were available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $50,000,000 or the borrowing base in effect from time to time. The Company’s initial borrowing base was set at $2,600,000. The initial loan under the facility with Citibank closed on June 29, 2006 in the principal amount of $2.6 million, bearing interest at a floating rate equal to LIBOR plus 2.5%, resulting in interest of approximately 8.2%. Interest only was payable during the term of the loan and the principal balance of the loan is due thirty-six months from closing. The facility is secured by a lien on substantially all of the Company’s producing and non-producing oil and gas properties and pipeline assets.
The Company used $1.393 million of the proceeds of the $2.6 million loan from Citibank to exercise the Company’s option to repurchase from Hoactzin Partners, L.P. (“Hoactzin”), the Company’s obligation to drill for Hoactzin the final six wells of the Company’s Twelve Well Program. Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin. He is also the sole shareholder and controlling person of Dolphin Management, Inc., the general partner of Dolphin Offshore Partners, L.P., which is the Company’s largest shareholder. A detailed description of the Twelve Well Program is set forth In “Item 1 – Business” under the subheading “Kansas Drilling Programs”.
If the Company had not exercised its repurchase option, Hoactzin would have received a 94% working interest in the final six wells of the Twelve Well Program until payout as established under the terms of the Twelve Well Program. However, as a result of the terms of the repurchase option, Hoactzin will receive only a 6.25% overriding royalty in the next six Company wells to be drilled, plus an additional 6.25% overriding royalty in the six Program Wells that have previously been drilled. As a further result of the repurchase, the Twelve Well Program was converted into a six well program, and because six wells had been drilled by the Company as of June 30, 2006 the drilling obligation in this program was satisfied upon exercise of the repurchase option. Consequently, as of June 30, 2006, all well-drilling obligations of the Company owed to participants have been satisfied as to the Twelve Well Program (offered to Hoactzin and converted to a 6-well program upon the Company’s repurchase of the obligation to drill the last six wells as described above) as well as the Company’s earlier Eight Well Program (offered to the former Series A preferred stockholders).
Under the terms of the Eight Well Program and Twelve (now Six) Well program, upon payment to the participants of 80% of the value invested in the Program from proceeds from production, the participants will pay the Company a management fee of 85% of their proceeds. As to the Eight Well Program, that point was reached in April 2007 resulting in an increase in revenues from these wells to the Company of approximately $50,000 per month at current volumes and prices. As to the Twelve (now 6) Well Program, that point is expected to be reached during the first half of 2008. It is anticipated, based upon current volumes and prices that this will result in an increase in revenues to the Company of approximately $50,000 per month.
On April 19, 2007 the Company borrowed an additional $700,000 from Citibank under the existing Citibank revolving credit facility. The additional borrowing resulted from Citibank’s increase in the Company’s borrowing base under the credit facility from $2.6 million to $3.3 million as a result of Citibank’s periodic borrowing base review conducted under the terms of credit facility. With the additional borrowing, the Company had borrowed the full amount of the $3.3 million borrowing base which was available to it under the Citibank revolving credit facility. Repayment of this additional sum was subject to the terms and conditions of the Citibank credit facility. The additional amount borrowed was used for additional development of the Company’s producing properties.
On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by the Company.
Under the facility as assigned to Sovereign, loans and letters of credit will be available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $20 million or the Company’s borrowing base in effect from time to time. The Company’s initial borrowing base with Sovereign was set at $7.0 million, an increase from its borrowing base of $3.3 million with Citibank prior to the assignment.
The Company’s initial borrowing on December 17, 2007 under its new facility with Sovereign was approximately $4.2 million which will bear interest at a floating rate equal to prime as published in the Wall Street Journal plus 0.25% resulting in a current interest rate of approximately 7.5%. Interest only is payable during the term of the loan and the principal balance of the loan is due December 31, 2010. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane Project assets.
The Company used a portion of the $4.2 million borrowed from Sovereign to pay off the funds it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign was used to pay bank fees and attorney fees relating to the assignment in the amount of approximately $75,000 and the balance of approximately $825,000 was used to pay a portion of the purchase price for equipment to be utilized in the Methane Project currently under construction in Church Hill, Tennessee by MMC, the Company’s wholly-owned subsidiary. See, “Item 1 - Business” under the subheading “The Methane Project”.
Net cash provided by operating activities for 2007 was $3,446,677 compared to net cash provided by operating activities of $4,353,966 in 2006. The Company’s net income in 2007 increased to $3,510,322 from $2,141,364 in 2006. The impact on cash provided by operating activities was due to the net income for 2007 and was increased by non-cash depletion, depreciation, and amortization of $1,631,468 and by non-cash compensation and services paid by insurance of equity instruments of $116,476. Cash flow provided in working capital items in 2007 was $211,742 compared to cash provided by working capital items of $122,152 in 2006. The Company’s net income for 2007 included a non-cash deferred tax asset for net operating loss carry forwards of $2,100,000.
Net cash provided by operating activities for 2006 was $4,353,966 compared to net cash provided by operating activities of $2,113,763 in 2005. The Company’s net income in 2006 increased to $2,141,364 from $1,088,028 in 2005. The impact on cash provided by operating activities was due to the net income for 2006 and was increased by non-cash depletion, depreciation, and amortization of $1,911,416 and by non-cash compensation and services paid by insurance of equity instruments of $159,160. Cash flow provided in working capital items in 2006 was $122,152 compared to cash used in working capital items of $209,601 in 2005. This resulted in 2006 from decreases from 2005 in accounts receivable of $434,565 offset by a decrease in other accrued liabilities of $251,327.
Net cash used in investing activities amounted to $3,145,764 for 2007 compared to net cash used in investment activities in the amount of $4,413,185 for 2006. The decrease in net cash used in investing activities during 2006 was primarily attributable to an increase in oil and gas properties of $5,190,611 offset by drilling program funds received of $3,850,000 and an increase in additions to methane project of $1,649,710.
Net cash used in investing activities amounted to $4,413,185 for 2006 compared to net cash provided by investment activities in the amount of $2,166,854 for 2005. The increase in net cash used in investing activities during 2006 was primarily attributable to an increase in oil and gas properties of $5,239,862 offset by a decreased drilling program portion of additional drilling costs of $1,067,400.
Net cash provided by financing activities increased to $1,556,261 in 2007 from cash provided by financing activities of $167,915 in 2006. In 2007 the primary sources of financing included proceeds from borrowings of $1,687,236 compared to $2,732,145 in 2006. The primary use of cash in financing activities in 2006 was to repay the drilling program liability of $2,324,400.
Net cash provided by financing activities increased to $167,915 in 2006 from cash used in financing activities of $4,287,383 in 2005. In 2006 the primary sources of financing included proceeds from borrowings of $2,732,145 compared to $155,075 in 2005. The primary use of cash in financing activities in 2006 was to repay the drilling program liability of $2,324,400.
Critical Accounting Policies....
The Company prepares its Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America, which requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. The Company considers the following policies to be the most critical in understanding the judgments that are involved in preparing the Company’s financial statements and the uncertainties that could impact the Company’s results of operations, financial condition and cash flows.
evenue 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.[b/b
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;
(b) the cost of investments in unevaluated properties excluded from the costs being amortized. No ceiling write-downs were recorded in 2007, 2006 or 2005.
Oil and Gas Reserves/Depletion Depreciation And Amortization of Oil and Gas Properties
The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated costs of plugging and abandonment, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.
The Company’s proved oil and gas reserves as of December 31, 2007 were determined by LaRoche Petroleum Consultants, Ltd. Projecting the effects of commodity prices on production, and timing of development expenditures includes many factors beyond the Company’s control. The future estimates of net cash flows from the Company’s proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates.
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.
Recent Accounting Pronouncements..
In July 2006, the FASB issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement 109" ("FIN 48"), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is "more-likely-than-not" to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the "more-likely-than-not" threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, the Company adopted FIN 48 on January 1, 2007. The Company does not expect the interpretation will have an impact on its results of operations or financial position.
In September 2006, the Securities and Exchange Commission staff published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The Company adopted SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. It defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurement. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. It clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company continues to evaluate the impact the adoption of this statement could have on its financial condition, results of operations and cash flows.
In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — As amended” (“SFAS 159”). SFAS 159 permits entities to elect to report eligible financial instruments at fair value subject to conditions stated in the pronouncement including adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial reporting by mitigating volatility in earnings related to current reporting requirements. The Company is considering the applicability of SFAS 159 and will determine if
adoption is appropriate. The effective date for SFAS 159 is for fiscal years beginning after November 15, 2007.
CONTRACTUAL OBLIGATIONS...
The following table summarizes the Company’s contractual obligations at December 31, 2007:
Payments Due By Period...
Contractual Obligations;
Total: $4,405,333
Less than 1 year;
Total: $89,560
1-3 years;
Total: $4,315,773
3-5 years;
Total $0.00
More than 5 years;
Total: $0.00
No cash dividends have been declared or paid by the Company for the periods presented.
On July 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 150 under which mandatorily redeemable preferred stock shall be reclassified at estimated fair value to a liability. Thus, in 2003, it was determined that each of the Company’s series of preferred stock qualifies as shares subject to mandatory redemption and should be classified as a liability.
The Company’s working capital surplus of 2,473,476.00 was attributable to high commodity prices as well as an increase in the borrowing base by $900,000 on December 17, 2007 and the funding of the Ten Well Program. The Company has expended approximately $1.5 million of these funds subsequent to year-end on the Methane Project and completing the Ten Well Program.
TGC.... AMEX..
Home Page:http://www.tengasco.com/
Profile..
Tengasco, Inc. engages in the exploration, production, and transportation of oil and natural gas in Kansas and Tennessee. The company also leases producing and non-producing properties, as well as owns pipeline and other infrastructure facilities to provide transportation services. It owns interests in 143 producing oil wells in the vicinity of Hays, Kansas; and 23 natural gas wells in the Swan Creek Field, Tennessee. The company markets its crude oil to refining companies, utilities, and private industry end-users; and natural gas to utilities, private industry end-users, and natural gas marketing companies. Tengasco was founded as Gold Deposit Mining & Milling Company in 1916 and changed its name to Onasco Companies, Inc. Further, it changed its name to Tengasco, Inc. in 1995. The company is based in Knoxville, Tennessee.
Yahoo Key Statistics: http://finance.yahoo.com/q/ks?s=TGC
Press Releases: http://www.tengasco.com/press_releases.shtml
Press Releases: http://finance.yahoo.com/q?s=TGC
Latest Qtr. report:
http://investorshub.advfn.com/boards/read_msg.asp?message_id=29079706
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My back of the napkin thoughts..
Net cash provided from operation were..
2005... $2,113,000
2006... $4,353,000
2007... $3,446,000 2007 includes 1,200,000 in expenses for work over of wells..
Reserves went from $26,627.00 in 2006 to $53,627,000 to $53,627,000 in 2007..
Net income:
2005 $1,088,000
2006 $2,141,000
2007 $1,410,000 + $2,100.00 from a tax credit.. Wells in Kansas where shut down in 2007 for an extended period due to ice conditions and the loss of electric power.. No damage was created to any equipment or wells..
Average Oil prices: Oil is purchased at wellhead by a gathering company at current price postings less 4% and payments are current for such sales..
2006 Average price recieved..$60.84
2007 Average price recieved..$66.42
**Gas prices received for sales of gas from the Swan Creek Field averaged $6.86 per Mcf in 2007, $7.27 per Mcf in 2006 and $8.74 per Mcf in 2005. Oil prices received for sales of oil from the Swan Creek field averaged $64.81 per barrel in 2007, and $60.39 per barrel in 2006, and. $53.90 per barrel in 2005.
***The Company realized revenues of $9,368,624 in 2007 compared to $9,001,681 in 2006 and compared to $7,172,876 in 2005. Revenues increased $366,943 from 2006 due primarily to an increase in oil prices in Kansas;
2007 Sales and earnings adjustments for 2008..
$9,368,624.00 revenues in 2007..
Earnings before Tax credits...2007 $1,410,000...
Add $800,000.00 in non recurring work over wells maintainence..
Add $1,200,000 in increased production from well programs..
Add $150.000 pickup for storm shutdowns..
Add $80,000 for increased Ngas prices recieved...
Total: $2,230,000 X .66 To account for taxes and Depletion = $1,471,000...
Total Earnings in 2008 should be at $66.42 with an oil Ave. of..$2,881,000Earnings added after after taxes and depletion.. after (T&D)$0.487 PS..
Oil @$79.70 Add $1,236,000 after (T&D) $4,117,000 $0.0696 PS
Oil @$86.34 Add $1,854,000 after (T&D) $4,735,000 $0.0800 PS
Oil @$92.98 Add $2,497,000 after (T&D} $5,378,000 $0.0909 PS
Oil @$99.63 Add $3,091,000 after (T&D) $5,972,000 $0.1010 PS
Oil @$106.00 Add $3,709,000 after (T&D) $6,590,000 $0.1114 PS
Oil @$112.91 Add $4,327,000 after (T&D) $7,208,000 $0.1218 PS
Oil @$119.55 Add $4,946,000 after (T&D) $7,827,000 $0.1323 PS
The earnings per share above only include existing production and do not include any further development on owned properites and leases that are presently being conducted.. EPS include all taxes and decline rates taken into consideraton when making asumptions.. I am long as My trading accounts indicates.. hank
===========================================
Reserves:
KNOXVILLE, TN--(MARKET WIRE)--Feb 6, 2008 -- Tengasco, Inc. (AMEX:TGC - News) announced today that the Company's total proved reserves at December 31, 2007 have more than doubled in value from year-end 2006. The reserve report prepared by the independent engineering firm of LaRoche Petroleum Consultants, Ltd. of Houston, Texas indicates that the value of the Company's total proved oil and gas reserves as of December 31, 2007 calculated at a net present value using a 10% discount factor was $53,627,086, up from the 2006 year-end total of $26,469,192. The LaRoche reserve report indicates that the value of the oil and gas reserves attributable to the Company's ownership interests :http://biz.yahoo.com/iw/080206/0358367.html
2007 Results of Operations:
TGC incurred a net income to holders of common stock of $3,510,322 or $0.06 per share in 2007 compared to a net income of $2,141,364 or $0.04 per share in 2006 and compared to a net income of $1,088,028 or $0.02 per share in 2005. The Company recognized a tax benefit for net operating loss carry forwards in the amount of $2,100,000 in 2007.
The Company realized revenues of $9,368,624 in 2007 compared to $9,001,681 in 2006 and compared to $7,172,876 in 2005. Revenues increased $366,943 from 2006 due primarily to an increase in oil prices in Kansas; prices averaged $66.42 in 2007 and 60.84 in 2006. Gross oil production in 2007 was just slightly less than 2006 resulting from the loss of production in January 2007 due to the electricity outage during an ice storm.
As a result of that storm, many counties in Kansas, including some counties where the Company has wells, lost power for the entire month of January. Producing wells in those counties were unable to produce without electricity to run the well pumps during the power outage. Consequently in January 2007 the Company saw production and revenue decline from monthly levels in late 2006. None of the Company’s producing wells were physically damaged by the ice storm or by non production during the absence of power, but the storm did substantially adversely impact production levels and sales in the first two months of 2007 while at the same time causing an increase in expenses. Eventually new poles and lines were rebuilt on a locally massive scale and electrical power was restored, and the Company experienced a rebound of production commencing in March 2007.
In 2007, the Company continued to focus its exploration and drilling activities in Kansas.
In 2007, the Company drilled 16 new wells on its Kansas Properties, of which 9 wells were under the ten well program discussed below in greater detail. Of these new wells, 10 are producing commercial quantities of oil. These new wells are producing approximately 135 barrels of oil per day.
The Company also continued in 2007 its program of work-overs of existing wells to increase production. The Company’s focus in 2007 on its Kansas oil production and the results achieved by the Company from its ongoing operations, drilling and work-overs are having a positive impact on the Company’s reserves resulting in the Company’s total proved reserves at December 31, 2007 having more than doubled in value from year-end 2006. Fifty-Six (56%) percent of that increase in reserve growth is attributable to the Company’s ongoing operational activities and the new Proved Undeveloped (PUD) future drilling locations that the Company has established as a result of these successes. See, Item 2, “Properties” – “Reserve Analysis” for a more detailed discussion of the Company’s reserves.
During 2007, the Company also continued its lease acquisition program in Kansas to acquire oil and gas leases in areas near its previous lease holdings where the Company believes there is a likelihood of additional oil production. The Company continued to collect and analyze substantial seismic data to aid it in its drilling operations. The Company intends in 2008 to continue to acquire additional leases in the area of its existing wells.
Production.....
Kansas Properties...
The Kansas Properties as of December 31, 2007 contained 192 leases totaling 28,934 acres in the vicinity of Hays, Kansas. The increase in the total volume of acreage of the Company’s Kansas Properties from 27,837 acres at the end of 2006 is primarily due to the purchase of two producing leases, the Heyl and RJ Thyfault. The Company focused its drilling, development, and exploration activities in Kansas in 2007 on evaluation of older producing properties, and those properties acquired in 2005 and 2006. Many of these leases, however, are still in effect because they are being held by production. The leases provide for a landowner royalty of 12.5%. Some wells are subject to an overriding royalty interest from 0.5% to 9%. The Company maintains a 100% working interest in most of its older wells and any undrilled acreage in Kansas. The terms for most of the Company’s newer leases in Kansas are from three to five years.
Kansas as a whole is of major significance to the Company. The majority of the Company’s current reserve value, current production, revenue, and future development objectives are centered in the Company’s ongoing interests in Kansas. By using 3-D seismic evaluation on existing locations owned by the Company in Kansas, the Company has added and continues to add proven direct offset locations. As a result of recent higher commodity prices for its oil, the Company has been able to drill from cash flow and attract favorable drilling partner programs in which the Company retains not only a carried beginning interest but a higher-than-industry-standard reversionary interest. The Company expects to continue this mix of company drilling and program drilling depending primarily on future cash flow and future oil prices. Breaking down the Company’s assets in Kansas into individual leases produces no apparent stand out leases that appear to be stand-alone principal properties. As a whole, however, our collective central Kansas holdings (see map below) are of major significance and as a group the most materially important segment of the Company as demonstrated by the following facts during the year ending December 31, 2007:
• Kansas accounted for 91.4% of the Company’s revenue (i.e. $8,560,097 of $9,368,624.)
• Kansas accounted for 86% of the Company’s total production measured in BOE (Barrel of Oil Equivalent)
• Kansas contributes $14.791 million in value of future proven development locations as of year end 2007, compared to just $567,000 in Tennessee
• The Company’s focus in 2008 will be to continue with offset seismic development, and leasing activity in Kansas. As a result, the Company’s undeveloped location value and total number of locations are expected to grow.
In 2007 the Company produced 178,311 barrels of oil in Kansas compared to 179,555 in 2006, a decrease of 1,244 barrels for the year. Additionally, the wells in the Eight Well Program (former Series “A”) reached the reversionary “flip point” in April 2007. This is the point at which the Company started receiving 85% of the participant’s interest plus our original interest of (19.3%) for an approximate total net interest to the Company equal to an 88% interest. In 2007 those wells produced 22,195 gross barrels of oil; the wells in the Twelve Well Program (former Series “B”) now converted to a six well program produced 15,864 gross barrels; wells polymered produced 19,502 barrels; and, the two new wells drilled produced 2,566 gross barrels in 2007.
During 2007 the Company drilled 9 of the 10 wells in the Ten Well Program and produced 3,649 barrels from the 5 wells that were completed by year-end. The other three wells that were drilled in 2007 were then completed in 2008. In March 2008, the tenth and final well in the Ten Well Program was both drilled and completed as a producer. As of the date of this report, nine of ten wells drilled in the Ten Well Program have been completed as producers and are producing approximately 106 barrels per day. During the first half of 2008 the Company expects the reversionary flip point for the Twelve Well Program (former Series “B”) now converted to a six well program, to be achieved.
Gas prices received for sales of gas from the Swan Creek Field averaged $6.86 per Mcf in 2007, $7.27 per Mcf in 2006 and $8.74 per Mcf in 2005. Oil prices received for sales of oil from the Swan Creek field averaged $64.81 per barrel in 2007, and $60.39 per barrel in 2006, and. $53.90 per barrel in 2005.
Production costs and taxes in 2007 increased to $4,322,833 from $3,287,233 in 2006 and $3,046,460 in 2005. The difference is due to increased work-overs to increase production, increased taxes, and overall cost increases of supplies in the industry.
Depletion, depreciation, and amortization for 2007 was $1,631,468, a decrease from $1,911,416 in 2006 due to production volumes added to future reserves from drilling activities. Depletion, depreciation, and amortization increased to $1,911,416 in 2006 from $1,605,043 in 2005. The increase in 2006 was due to a change in focus by the Company toward drilling in Kansas rather than in Tennessee, therefore removing drilling and development locations in Tennessee.
The Company’s general and administrative costs of $1,417,001 in 2007 remained generally consistent with 2006 levels of $1,293,109 and 2005 levels of $1,322,616. The 2007, 2006 and 2005 costs included non-cash charges related to stock options of $116,476, $159,160 and $103,400 respectively.
The increase in interest expense in 2007 relates to the borrowing base increase of the Citibank credit facility in 2007. Interest expense for 2006 decreased significantly over 2005 levels. This was due to the conversion of the Company’s preferred stock, which was subject to mandatory redemption, into either interest in a drilling program, common stock or cash payoffs. As of December 31, 2006, the Company’s only debt financing were vehicle loans totaling $195,801 and the CitiBank loan of $2,600,000.
The Company’s public relations costs remained stable at $21,605 for 2007, compared to $26,037 for 2006 and $30,020 for 2005 as the Company continued to apply cost saving methods in the preparation of its annual report and in publishing of press releases.
Professional fees in 2007 were $232,197 compared to $173,932 in 2006. This was due to the Company commencing its review of its internal controls over its financial reporting in accordance with Item 308(T) of Regulation S-K. Professional fees in 2006 decreased from 2005 levels as the Company’s litigation was settled.
The Company recorded a deferred tax asset of $2,100,000 in 2007 relating to the Company’s net operating loss carry forwards. The Company recorded a gain on disposal of preferred stock of $655,746 in 2005.
Liquidity and Capital Resources .....
On June 29, 2006, the Company closed a $50,000,000 revolving senior credit facility between the Company and Citibank Texas, N.A. in its own capacity and also as agent for other banks. Under the facility, loans and letters of credit were available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $50,000,000 or the borrowing base in effect from time to time. The Company’s initial borrowing base was set at $2,600,000. The initial loan under the facility with Citibank closed on June 29, 2006 in the principal amount of $2.6 million, bearing interest at a floating rate equal to LIBOR plus 2.5%, resulting in interest of approximately 8.2%. Interest only was payable during the term of the loan and the principal balance of the loan is due thirty-six months from closing. The facility is secured by a lien on substantially all of the Company’s producing and non-producing oil and gas properties and pipeline assets.
The Company used $1.393 million of the proceeds of the $2.6 million loan from Citibank to exercise the Company’s option to repurchase from Hoactzin Partners, L.P. (“Hoactzin”), the Company’s obligation to drill for Hoactzin the final six wells of the Company’s Twelve Well Program. Peter E. Salas, the Chairman of the Board of Directors of the Company, is the controlling person of Hoactzin. He is also the sole shareholder and controlling person of Dolphin Management, Inc., the general partner of Dolphin Offshore Partners, L.P., which is the Company’s largest shareholder. A detailed description of the Twelve Well Program is set forth In “Item 1 – Business” under the subheading “Kansas Drilling Programs”.
If the Company had not exercised its repurchase option, Hoactzin would have received a 94% working interest in the final six wells of the Twelve Well Program until payout as established under the terms of the Twelve Well Program. However, as a result of the terms of the repurchase option, Hoactzin will receive only a 6.25% overriding royalty in the next six Company wells to be drilled, plus an additional 6.25% overriding royalty in the six Program Wells that have previously been drilled. As a further result of the repurchase, the Twelve Well Program was converted into a six well program, and because six wells had been drilled by the Company as of June 30, 2006 the drilling obligation in this program was satisfied upon exercise of the repurchase option. Consequently, as of June 30, 2006, all well-drilling obligations of the Company owed to participants have been satisfied as to the Twelve Well Program (offered to Hoactzin and converted to a 6-well program upon the Company’s repurchase of the obligation to drill the last six wells as described above) as well as the Company’s earlier Eight Well Program (offered to the former Series A preferred stockholders).
Under the terms of the Eight Well Program and Twelve (now Six) Well program, upon payment to the participants of 80% of the value invested in the Program from proceeds from production, the participants will pay the Company a management fee of 85% of their proceeds. As to the Eight Well Program, that point was reached in April 2007 resulting in an increase in revenues from these wells to the Company of approximately $50,000 per month at current volumes and prices. As to the Twelve (now 6) Well Program, that point is expected to be reached during the first half of 2008. It is anticipated, based upon current volumes and prices that this will result in an increase in revenues to the Company of approximately $50,000 per month.
On April 19, 2007 the Company borrowed an additional $700,000 from Citibank under the existing Citibank revolving credit facility. The additional borrowing resulted from Citibank’s increase in the Company’s borrowing base under the credit facility from $2.6 million to $3.3 million as a result of Citibank’s periodic borrowing base review conducted under the terms of credit facility. With the additional borrowing, the Company had borrowed the full amount of the $3.3 million borrowing base which was available to it under the Citibank revolving credit facility. Repayment of this additional sum was subject to the terms and conditions of the Citibank credit facility. The additional amount borrowed was used for additional development of the Company’s producing properties.
On December 17, 2007, Citibank assigned the Company’s revolving credit facility with Citibank to Sovereign Bank of Dallas, Texas (“Sovereign”) as requested by the Company.
Under the facility as assigned to Sovereign, loans and letters of credit will be available to the Company on a revolving basis in an amount outstanding not to exceed the lesser of $20 million or the Company’s borrowing base in effect from time to time. The Company’s initial borrowing base with Sovereign was set at $7.0 million, an increase from its borrowing base of $3.3 million with Citibank prior to the assignment.
The Company’s initial borrowing on December 17, 2007 under its new facility with Sovereign was approximately $4.2 million which will bear interest at a floating rate equal to prime as published in the Wall Street Journal plus 0.25% resulting in a current interest rate of approximately 7.5%. Interest only is payable during the term of the loan and the principal balance of the loan is due December 31, 2010. The Sovereign facility is secured by substantially all of the Company’s producing and non-producing oil and gas properties and pipeline and the Company’s Methane Project assets.
The Company used a portion of the $4.2 million borrowed from Sovereign to pay off the funds it previously borrowed from Citibank. The remaining $900,000 borrowed from Sovereign was used to pay bank fees and attorney fees relating to the assignment in the amount of approximately $75,000 and the balance of approximately $825,000 was used to pay a portion of the purchase price for equipment to be utilized in the Methane Project currently under construction in Church Hill, Tennessee by MMC, the Company’s wholly-owned subsidiary. See, “Item 1 - Business” under the subheading “The Methane Project”.
Net cash provided by operating activities for 2007 was $3,446,677 compared to net cash provided by operating activities of $4,353,966 in 2006. The Company’s net income in 2007 increased to $3,510,322 from $2,141,364 in 2006. The impact on cash provided by operating activities was due to the net income for 2007 and was increased by non-cash depletion, depreciation, and amortization of $1,631,468 and by non-cash compensation and services paid by insurance of equity instruments of $116,476. Cash flow provided in working capital items in 2007 was $211,742 compared to cash provided by working capital items of $122,152 in 2006. The Company’s net income for 2007 included a non-cash deferred tax asset for net operating loss carry forwards of $2,100,000.
Net cash provided by operating activities for 2006 was $4,353,966 compared to net cash provided by operating activities of $2,113,763 in 2005. The Company’s net income in 2006 increased to $2,141,364 from $1,088,028 in 2005. The impact on cash provided by operating activities was due to the net income for 2006 and was increased by non-cash depletion, depreciation, and amortization of $1,911,416 and by non-cash compensation and services paid by insurance of equity instruments of $159,160. Cash flow provided in working capital items in 2006 was $122,152 compared to cash used in working capital items of $209,601 in 2005. This resulted in 2006 from decreases from 2005 in accounts receivable of $434,565 offset by a decrease in other accrued liabilities of $251,327.
Net cash used in investing activities amounted to $3,145,764 for 2007 compared to net cash used in investment activities in the amount of $4,413,185 for 2006. The decrease in net cash used in investing activities during 2006 was primarily attributable to an increase in oil and gas properties of $5,190,611 offset by drilling program funds received of $3,850,000 and an increase in additions to methane project of $1,649,710.
Net cash used in investing activities amounted to $4,413,185 for 2006 compared to net cash provided by investment activities in the amount of $2,166,854 for 2005. The increase in net cash used in investing activities during 2006 was primarily attributable to an increase in oil and gas properties of $5,239,862 offset by a decreased drilling program portion of additional drilling costs of $1,067,400.
Net cash provided by financing activities increased to $1,556,261 in 2007 from cash provided by financing activities of $167,915 in 2006. In 2007 the primary sources of financing included proceeds from borrowings of $1,687,236 compared to $2,732,145 in 2006. The primary use of cash in financing activities in 2006 was to repay the drilling program liability of $2,324,400.
Net cash provided by financing activities increased to $167,915 in 2006 from cash used in financing activities of $4,287,383 in 2005. In 2006 the primary sources of financing included proceeds from borrowings of $2,732,145 compared to $155,075 in 2005. The primary use of cash in financing activities in 2006 was to repay the drilling program liability of $2,324,400.
Critical Accounting Policies....
The Company prepares its Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America, which requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. The Company considers the following policies to be the most critical in understanding the judgments that are involved in preparing the Company’s financial statements and the uncertainties that could impact the Company’s results of operations, financial condition and cash flows.
evenue 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.[b/b
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;
(b) the cost of investments in unevaluated properties excluded from the costs being amortized. No ceiling write-downs were recorded in 2007, 2006 or 2005.
Oil and Gas Reserves/Depletion Depreciation And Amortization of Oil and Gas Properties
The capitalized costs of oil and gas properties, plus estimated future development costs relating to proved reserves and estimated costs of plugging and abandonment, net of estimated salvage value, are amortized on the unit-of-production method based on total proved reserves. The costs of unproved properties are excluded from amortization until the properties are evaluated, subject to an annual assessment of whether impairment has occurred.
The Company’s proved oil and gas reserves as of December 31, 2007 were determined by LaRoche Petroleum Consultants, Ltd. Projecting the effects of commodity prices on production, and timing of development expenditures includes many factors beyond the Company’s control. The future estimates of net cash flows from the Company’s proved reserves and their present value are based upon various assumptions about future production levels, prices, and costs that may prove to be incorrect over time. Any significant variance from assumptions could result in the actual future net cash flows being materially different from the estimates.
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.
Recent Accounting Pronouncements..
In July 2006, the FASB issued FASB Interpretation No. 48, "Accounting for Uncertainty in Income Taxes - an interpretation of FASB Statement 109" ("FIN 48"), which clarifies the accounting for uncertainty in tax positions taken or expected to be taken in a tax return, including issues relating to financial statement recognition and measurement. FIN 48 provides that the tax effects from an uncertain tax position can be recognized in the financial statements only if the position is "more-likely-than-not" to be sustained if the position were to be challenged by a taxing authority. The assessment of the tax position is based solely on the technical merits of the position, without regard to the likelihood that the tax position may be challenged. If an uncertain tax position meets the "more-likely-than-not" threshold, the largest amount of tax benefit that is more than 50 percent likely to be recognized upon ultimate settlement with the taxing authority, is recorded. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006, with the cumulative effect of the change in accounting principle recorded as an adjustment to opening retained earnings. Consistent with the requirements of FIN 48, the Company adopted FIN 48 on January 1, 2007. The Company does not expect the interpretation will have an impact on its results of operations or financial position.
In September 2006, the Securities and Exchange Commission staff published Staff Accounting Bulletin SAB No. 108 (“SAB 108”), "Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements." SAB 108 addresses quantifying the financial statement effects of misstatements, specifically, how the effects of prior year uncorrected errors must be considered in quantifying misstatements in the current year financial statements. SAB 108 is effective for fiscal years ending after November 15, 2006. The Company adopted SAB 108 in the fourth quarter of 2006. Adoption did not have an impact on the Company’s consolidated financial statements.
In September 2006, the FASB issued SFAS 157, Fair Value Measurements. The standard provides guidance for using fair value to measure assets and liabilities. It defines fair value, establishes a framework for measuring fair value under generally accepted accounting principles and expands disclosures about fair value measurement. Under the standard, fair value refers to the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants in the market in which the reporting entity transacts. It clarifies the principle that fair value should be based on the assumptions market participants would use when pricing the asset or liability. In support of this principle, the standard establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. Statement 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007. The Company continues to evaluate the impact the adoption of this statement could have on its financial condition, results of operations and cash flows.
In February 2007, the FASB issued SFAS No. 159 “The Fair Value Option for Financial Assets and Financial Liabilities — As amended” (“SFAS 159”). SFAS 159 permits entities to elect to report eligible financial instruments at fair value subject to conditions stated in the pronouncement including adoption of SFAS 157 discussed above. The purpose of SFAS 159 is to improve financial reporting by mitigating volatility in earnings related to current reporting requirements. The Company is considering the applicability of SFAS 159 and will determine if
adoption is appropriate. The effective date for SFAS 159 is for fiscal years beginning after November 15, 2007.
CONTRACTUAL OBLIGATIONS...
The following table summarizes the Company’s contractual obligations at December 31, 2007:
Payments Due By Period...
Contractual Obligations;
Total: $4,405,333
Less than 1 year;
Total: $89,560
1-3 years;
Total: $4,315,773
3-5 years;
Total $0.00
More than 5 years;
Total: $0.00
No cash dividends have been declared or paid by the Company for the periods presented.
On July 1, 2003, the Company adopted the provisions of Statement of Financial Accounting Standards No. 150 under which mandatorily redeemable preferred stock shall be reclassified at estimated fair value to a liability. Thus, in 2003, it was determined that each of the Company’s series of preferred stock qualifies as shares subject to mandatory redemption and should be classified as a liability.
The Company’s working capital surplus of 2,473,476.00 was attributable to high commodity prices as well as an increase in the borrowing base by $900,000 on December 17, 2007 and the funding of the Ten Well Program. The Company has expended approximately $1.5 million of these funds subsequent to year-end on the Methane Project and completing the Ten Well Program.
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