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| TGC > SEC Filings for TGC > Form 10-Q/A on 13-Nov-2009 | All Recent SEC Filings |
13-Nov-2009
Quarterly Report
Results of Operations and Financial Condition
During the first nine months of 2009, the Company sold 175,948 gross barrels of oil from its Kansas Properties comprised of 182 producing oil wells. Of the 175,948 gross barrels, 127,590 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 nine months of 2009 of 127,590 net barrels of oil compares to 109,494 barrels sold to the Company's interest in the first nine months of 2008. Although the Company's production for the first nine months of 2009 increased by 17% from the first nine months in 2008, the Company's net revenues from the Kansas properties decreased from $12.1 million in the first nine months of 2008 to $6.2 million in the first nine months of 2009. This decrease was due to a drop in oil prices to an average of $49.74 per barrel in 2009 from an average of $106.53 per barrel in 2008. The Company's sales from Tennessee for the first nine months of 2009 included $0.2 million from oil sales, $0.1 million from Swan Creek gas sales, and $0.1 million from Manufactured Methane sales.
Comparison of the Quarters Ended September 30, 2009 and 2008
The Company recognized $2.6 million in revenues during the third quarter of 2009 compared to $5.1 million in the third quarter of 2008. The decrease in revenues was due to a sharp decrease in oil prices in 2009. Oil prices in the third quarter of 2009 averaged $60.96 per barrel compared to $110.85 per barrel in the third quarter of 2008. The Company realized a net loss attributable to common shareholders of $(0.4 million) or $(0.01) per share of common stock during the third quarter of 2009, compared to a net income in the third quarter of 2008 to common shareholders of $1.6 million or $0.03 per share of common stock. The Company recorded non-cash unrealized loss on derivatives of $(0.6 million) for the third quarter 2009 and non-cash income tax expense of $0.8 million for the third quarter net income in 2008.
Production costs and taxes in the third quarter of 2009 decreased to $1.4 million from $1.5 million in the third quarter of 2008. This decrease is due to the Company's cost-cutting measures implemented in response to reduced oil prices as well as lower production in the third quarter 2009 as compared to 2008.
Depreciation, depletion, and amortization expense in the third quarter of 2009 decreased to $0.5 million from $0.6 million in the third quarter 2008. The depletion percentage has remained consistent with the total oil and gas properties.
Interest expense was $0.2 million in both third quarter of 2009 and 2008.
Comparison of the Nine Months Ended September 30, 2009 and 2008
The Company recognized $6.8 million in revenues during the first nine months of 2009 compared to $13.0 million in the first nine months of 2008. The decrease in revenues was due to a decrease in oil prices in 2009. Oil prices in the first nine months of 2009 averaged $49.74 per barrel compared to $106.53 per barrel in the first nine months of 2008. The Company realized a net loss attributable to common shareholders of $(0.9 million) or $(0.02) per share of common stock during the first nine months of 2009, compared to a net income in the first nine months of 2008 to common shareholders of $8.8 million or $0.15 per share of common stock. Approximately $3.4 million [38%] of this income was attributable to the net effects of recognizing the Company's deferred tax assets in 2008. The Company recorded non-cash unrealized loss on derivatives of $(0.6 million) for the first nine months of 2009, the remaining net operating loss carry forwards of $5.2 million in the first nine months of 2008 and recorded non-cash income tax expense of $1.8 million for the first nine months of 2008.
Production costs and taxes in the first nine months of 2009 decreased to $3.7 million from $4.2 million in the first nine months of 2008. This decrease is due to the Company's cost-cutting measures implemented in response to reduced oil prices during 2009. Depreciation, depletion, and amortization expense for the first nine months of 2009
was $1.4 million compared to $1.5 million in the first nine months of 2008. The depletion percentage has remained consistent with the total oil and gas properties.
Interest expense for the first nine months of 2009 increased to $0.5 million from $0.4 million due to the additional borrowing for the Riffe field purchase in July 2008.
Liquidity and Capital Resources
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 are 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 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'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.
On June 2, 2008, the Company entered into an amendment to its credit facility with Sovereign whereby the Company's borrowing base was increased by the Bank as a result of its review of the Company's currently owned producing properties. The borrowing base was raised to $11 million effective June 2, 2008. The Company had previously utilized about $4.2 million of the facility, leaving approximately $6.8 million then available for use by the Company upon this borrowing base increase. The Company used $5.35 million of the then available $6.8 million for the purchase of the Riffe Field properties in Kansas. The total borrowing by the Company under the facility as of the date of this Report is $9.9 million.
Effective February 5, 2009, the Company amended its credit facility with Sovereign to provide for a monthly reduction of the Bank's commitment by $0.15 million per month for the five month period of February through June 2008. This commitment reduction is not a cash payment obligation of the Company but had the effect of reducing the Company's available borrowing base in monthly increments of $0.15 million so that by June 2009 the Company's available borrowing base under the Sovereign facility was reduced by $0.75 million from $11.0 million to $10.25 million.
On July 9, 2009 the Company's borrowing base was increased from $10.25 million to $11.0 million under the revolving senior credit facility between the Company and Sovereign. The Company's borrowing base was increased on the completion of the regular semiannual borrowing base review by Sovereign. The $11.0 million borrowing base is again subject to a monthly available-credit reduction (MCR) of $.15 million per month beginning August 5, 2009. At September 30, 2009, the borrowing base was $10.7 million. As the borrowing base under the Company's Sovereign Bank revolving credit facility is reduced, the Company would be required to pay down its borrowings
under the revolving credit facility so that outstanding borrowings do not exceed the reduced borrowing base. This could further reduce the cash available to the Company for capital spending and, if the Company did not have sufficient capital to reduce its borrowing level, could cause the Company to default under its revolving credit facility with Sovereign Bank.
As of September 30, 2009, the Company was out of compliance on the Leverage Ratio and Interest Coverage Ratio covenants under the credit facility. The Company was in compliance with the remaining financial covenants under the credit facility. The noncompliance occurred primarily as a result of the low commodity prices in the last quarter of 2008 and first quarter of 2009 that are included in the covenant compliance calculations. The Company has received a waiver from Sovereign Bank for breach of these covenants for the quarter ended September 30, 2009. It is possible that the Company may be out of compliance with one or more of the financial covenants in the fourth quarter of 2009 or future quarters due to the volatility of oil or gas prices. The Company anticipates, but there can be no assurances, that Sovereign Bank will waive the noncompliance of these covenants if such noncompliance occurs in the fourth quarter of 2009 or future quarters.
Derivative Activities
On July 28, 2009 the Company entered into a two-year agreement on crude oil pricing applicable to a portion of the Company's crude oil production volumes. The agreement was effective beginning August 1, 2009. The "costless collar" agreement has a $60.00 per barrel floor an $81.50 per barrel cap on a volume of 9,500 barrels per month during the period from August 1, 2009 through December 31, 2010, and 7,375 barrels per month from January 1 through July 31, 2011. To effectuate the collar the Company entered into an International Swaps and Derivatives Master Agreement and an intercreditor agreement among the Company, its subsidiaries, Macquarie Bank Limited as counterparty, and Sovereign Bank of Dallas, Texas, the Company's senior lender. The prices referenced in this agreement are WTI NYMEX. While the agreement is based on WTI NYMEX prices, the Company receives a price based on Kansas Common plus bonus, which results in approximately $7 per barrel lower than NYMEX at current prices.
The Company pays no fee for this agreement. If prices remain between the floor and ceiling prices, no cash activity occurs under the agreement. If crude oil prices fall below $60.00 per barrel, WTI NYMEX, the counterparty will pay the Company the excess of $60 per barrel over the WTI NYMEX price (times the number of barrels covered by the agreement). If prices rise above $81.50 per barrel WTI NYMEX, the Company will pay the counterparty the excess of the WTI NYMEX price over $81.50 per barrel (times the number of barrels covered by the agreement). The agreement is intended to provide some protection to the Company from any return to the levels of crude oil pricing as experienced in late 2008 and early 2009 when WTI NYMEX crude prices were in the $30 dollar per barrel range. The average price per barrel received by the Company in the
first quarter of 2009 was $35.74, $52.52 for the second quarter 2009, and $60.96 for the third quarter 2009, however the Company's actual prices received per barrel are based on Kansas Common plus bonus, which results in approximately $7 per barrel less than current WTI NYMEX prices. The agreement operates to provide price support on the volumes when WTI NYMEX prices for crude oil are below $60.00 per barrel, but the upside potential on the volumes if WTI NYMEX prices exceed $81.50 is lost to the Company. The Company's current average production is about 15,000 barrels per month, so the downside protection on price would apply to only about two-thirds of current production. However, if WTI NYMEX prices exceed $81.50 per barrel, the Company will receive that upside benefit as to the remaining one third of current production volumes that are above the agreement volume. This agreement is primarily intended to help maintain and stabilize cash flow from operations if lower oil prices return, while providing at least some upside if prices increase above the cap. If lower oil prices return, this agreement may help to maintain the Company's production levels of crude oil by enabling the company to perform some ongoing polymer or other workover treatments on then-existing producing wells in Kansas.
At September 30, 2009 the Company recorded a $(0.6 million) unrealized derivative loss based on anticipated future performance under the agreement. However, through September 30, 2009, no settlement payment has been required under the agreement as WTI NYMEX prices through that date remained within the collar.
Critical Accounting Policies
The Company prepares its Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America, which requires the Company to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the year. Actual results could differ from those estimates. The Company considers the following policies to be the most critical in understanding the judgments that are involved in preparing the Company's financial statements and the uncertainties that could impact the Company's results of operations, financial condition, and cash flows.
Revenue Recognition
The Company uses the sales method of accounting for natural gas and oil revenues. Under this method, revenues are recognized based on actual volumes of oil and gas sold to purchasers. Natural gas meters are placed at the customers' locations and usage is billed monthly.
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. However, costs 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 are excluded from the costs being amortized.
Oil and Gas Reserves/Depletion Depreciation & 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, 2008 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' closures as well as the estimated closing costs, discounted at the credit adjusted risk free rate of 8%. Quarterly, management accretes the 8% discount into the liability and makes other adjustments to the liability for well retirements incurred during the period.
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