Critical Accounting Policies
Full Cost Method of Accounting
We use the full cost method of accounting for our investments in oil and gas properties. Under this method, all acquisition, exploration and development costs, including certain related employee costs, incurred for the purpose of exploring for and developing oil and natural gas are capitalized. Acquisition costs include costs incurred to purchase, lease or otherwise acquire property. Exploration costs include the costs of drilling exploratory wells, including those in progress and geological and geophysical service costs in exploration activities. Development costs include the costs of drilling development wells and costs of completions, platforms, facilities and pipelines. Costs associated with production and general corporate activities are expensed in the period incurred. Sales of proved oil and gas properties are accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized costs and proved reserves of oil and gas.
The costs associated with unevaluated properties are not initially included in the amortization base and primarily relate to ongoing exploration activities, unevaluated leasehold acreage and delay rentals, seismic data and capitalized interest. These costs are either transferred to the amortization base with the costs of drilling the related well or are assessed quarterly for possible impairment or reduction in value.
We compute the provision for depletion of oil and gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Unevaluated costs and related carrying costs are excluded from the amortization base until the properties associated with these costs are evaluated. In addition to costs associated with evaluated properties, the amortization base includes estimated future development costs related to non-producing reserves. Our depletion expense is affected by the estimates of future development costs, unevaluated costs and proved reserves, and changes in these estimates could have an impact on our future earnings. We capitalize certain internal costs that are directly identified with acquisition, exploration and development activities. The capitalized internal costs include salaries, employee benefits, costs of consulting services and other related expenses and do not include costs related to production, general corporate overhead or similar activities. We also capitalize a portion of the interest costs incurred on our debt. Capitalized interest is calculated using the amount of our unevaluated property and our effective borrowing rate. Capitalized costs of oil and gas properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, discounted at 10 percent, plus the lower of cost or fair value of unproved properties, as adjusted for related income tax effects (the full cost ceiling). If capitalized costs exceed the full cost ceiling, the excess is charged to write-down of oil and gas properties in the quarter in which the excess occurs.
The prices of oil and natural gas have declined significantly since June 2008. At March 31, 2009, we computed the estimated future net cash flows from our proved oil and gas reserves, discounted at 10%, using quarter-end prices, including hedges, of $3.87 per Mcfe and $52.34 per barrel. Due to the low market prices at March 31, 2009, our capitalized costs exceeded the full cost ceiling, resulting in a $103.6 million non-cash ceiling test write-down of our oil and gas properties.
At September 30, 2009, we computed the estimated future net cash flows from our proved oil and gas reserves, discounted at 10%, using quarter end prices, including the effects of hedges, of $3.35 per Mcfe and $70.72 per barrel. Due to the market price for gas at September 30, 2009, our capitalized costs exceeded the full cost ceiling by approximately $18.5 million. Our cash flow hedges in place at September 30, 2009 increased the full cost ceiling by approximately $39 million. Subsequent to September 30, 2009, the market prices for oil and gas improved. Using oil and gas prices in effect at the end of October 2009, our capitalized costs no longer exceeded the full cost ceiling. As a result, we did not record a write-down of our oil and gas properties at September 30, 2009. Given the volatility of oil and gas prices, it is probable that our estimate of discounted future net cash flows from proved oil and gas reserves will change in the near term. If oil or gas prices decline, even for only a short period of time, or if we have downward revisions to our estimated proved reserves, it is possible that additional write-downs of oil and gas properties could occur in the future.
Future Abandonment Costs
Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems, wells and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering consultants. Because these costs typically extend many years into the future, estimating these future costs is difficult and requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including changing technology, the timing of estimated costs, the impact of future inflation on current cost estimates and the political and regulatory environment.

Reserve Estimates
Our estimates of proved oil and gas reserves constitute quantities that we are reasonably certain of recovering in future years from known reservoirs under existing economic and operating conditions. At the end of each year, our proved reserves are estimated by independent petroleum engineers in accordance with guidelines established by the SEC. These estimates, however, represent projections based on geologic and engineering data. Reserve engineering is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. The accuracy of any reserve estimate is a function of the quantity and quality of available data, engineering and geological interpretation and professional judgment. Estimates of economically recoverable oil and gas reserves and future net cash flows necessarily depend upon a number of variable factors and assumptions, such as historical production from the area compared with production from other producing areas, the assumed effect of regulations by governmental agencies, and assumptions governing future oil and gas prices, future operating costs, severance taxes, development costs and workover costs. The future drilling costs associated with reserves assigned to proved undeveloped locations may ultimately increase to the extent that these reserves may be later determined to be uneconomic. Any significant variance in the assumptions could materially affect the estimated quantity and value of the reserves, which could affect the carrying value of our oil and gas properties and/or the rate of depletion of such oil and gas properties. On December 29, 2008, the SEC adopted new rules related to modernizing accounting and disclosure requirements for oil and natural gas companies. The new disclosure requirements include provisions that permit the use of new technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. The new rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The new disclosure requirements also require companies to report the independence and qualifications of third party preparers of reserves and file reports when a third party is relied upon to prepare reserves estimates. A significant change to the rules involves the pricing at which reserves are measured. The new rules utilize a 12-month average price using beginning of the month pricing (January 1 to December 1) to report oil and natural gas reserves rather than year-end prices. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization. The new rules are effective January 1, 2010 with first reporting for calendar year companies in their 2009 annual reports. Early adoption is not permitted. We have not completed our evaluation of the impact of the new rules on our accounting and disclosure.
Derivative Instruments
The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. At inception, all of our commodity derivative instruments represent hedges of the price of future oil and gas production. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income until the hedged oil or natural gas quantities are produced. If a hedge becomes ineffective because the hedged production does not occur, or the hedge otherwise does not qualify for hedge accounting treatment, the changes in the fair value of the derivative are recorded in the income statement as derivative income or expense. Our hedges are specifically referenced to NYMEX prices. We evaluate the effectiveness of our hedges at the time we enter the contracts, and periodically over the life of the contracts, by analyzing the correlation between NYMEX prices and the posted prices we receive from our designated production. Through this analysis, we are able to determine if a high correlation exists between the prices received for the designated production and the NYMEX prices at which the hedges will be settled. At September 30, 2009, our derivative instruments were considered effective cash flow hedges.
Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX prices, discount rates and price movements. As a result, we obtain the fair value of our commodity derivatives using an independent third-party's valuation model that utilizes market-corroborated inputs that are observable over the term of the derivative contract. Our fair value calculations also incorporate an estimate of the counterparties' default risk for derivative assets and an estimate of our default risk for derivative liabilities.

New Accounting Standards
In June 2009, the FASB issued Accounting Standards Update No. 2009-01, "Generally Accepted Accounting Principles" (ASC Topic 105) which establishes the FASB Accounting Standards Codification ("the Codification" or "ASC") as the official single source of authoritative U.S. generally accepted accounting principles ("GAAP"). All existing accounting standards are superseded. All other accounting guidance not included in the Codification will be considered non-authoritative.
The Codification is not intended to change GAAP, but it will change the way GAAP is organized and presented. The Codification is effective for our third-quarter 2009 financial statements and the principal impact on our financial statements is limited to disclosures therein as all future references to authoritative accounting literature will be referenced in accordance with the Codification. In order to ease the transition to the Codification, we are providing cross-references to the standards issued and adopted prior to the adoption alongside the Codification references.
Effective January 1, 2009, we adopted ASC Topic 815 (SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities-an amendment of FASB Statement No.133"). ASC Topic 815 requires enhanced disclosures about derivative and hedging activities, and is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. The adoption of ASC Topic 815 had no impact on our financial position or results of operations.
Effective January 1, 2009, we adopted ASC Topic 260-10-45 (FSP 03-6-1). ASC Topic 260-10-45 provides that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be included in the computation of earnings per share using the two-class method described in ASC Topic 260-10 (SFAS 128). See Note 4 regarding the impact of the adoption on our calculation of earnings per share.
In April 2009, the FASB issued FSPs to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities. ASC Topic 820-10-65 (FSP FAS 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly,") provides guidelines for making fair value measurements more consistent with the principles presented in ASC Topic 820 (SFAS No. 157). ASC Topic 825-10-65 (FSP FAS 107-1) and ASC Topic 270 (APB 28-1, "Interim Disclosures about Fair Value of Financial Instruments,") enhance consistency in financial reporting by increasing the frequency of fair value disclosures. These FSPs are effective for interim and annual periods ending after June 15, 2009 and we adopted the provisions of these FSPs for the period ending June 30, 2009. The adoption of these FSPs did not have a material impact on our financial position or results of operations.
We adopted ASC Topic 855 (SFAS No. 165, "Subsequent Events") in the second quarter of 2009. ASC Topic 855 establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is new terminology, the standard is based on the same principles as those that previously existed. ASC Topic 855 includes a new required disclosure of the date through which an entity has evaluated subsequent events. The adoption of ASC Topic 855 did not have an impact on our financial position or results of operations.

Results of Operations
The following table sets forth certain information with respect to our oil and
gas operations for the periods noted. These historical results are not
necessarily indicative of results to be expected in future periods.

                                Three Months Ended                  Nine Months Ended
                                   September 30,                      September 30,
                               2009             2008             2009              2008
 Production:
 Oil (Bbls)                     137,077          137,929           450,676           504,509
 Gas (Mcf)                    7,169,167        7,214,427        23,944,666        21,322,903
 Total Production (Mcfe)      7,991,629        8,042,001        26,648,722        24,349,957

 Sales:
 Total oil sales           $ 10,324,647     $ 15,695,498     $  29,028,227     $  53,362,415
 Total gas sales             39,857,782       61,291,924       135,764,007       189,057,801

 Total oil and gas sales   $ 50,182,429     $ 76,987,422     $ 164,792,234     $ 242,420,216


 Average sales prices:
 Oil (per Bbl)             $      75.32     $     113.79     $       64.41     $      105.77
 Gas (per Mcf)                     5.56             8.50              5.67              8.87
 Per Mcfe                          6.28             9.57              6.18              9.96

The above sales and average sales prices include additions (reductions) related to the settlement of gas hedges of $20,996,000 and ($3,925,000) and the settlement of oil hedges of $1,167,000 and ($1,567,000) for the three months ended September 30, 2009 and 2008, respectively. The above sales and average sales prices include additions (reductions) related to the settlement of gas hedges of $57,415,000 and ($11,538,000) and the settlement of oil hedges of $4,682,000 and ($4,504,000) for the nine months ended September 30, 2009 and 2008, respectively.
Net income available to common stockholders totaled $4,453,000 and $16,758,000 for the quarters ended September 30, 2009 and 2008, respectively, while net income (loss) available to common stockholders for the nine-month periods ended September 30, 2009 and 2008 totaled ($54,758,000) and $52,694,000, respectively. The decrease during the 2009 periods was primarily attributable to the following:
Production. Oil and gas production during the third quarter of 2009 approximated production during the 2008 period. Oil production during the nine-month period ended September 30, 2009 decreased 11% from the comparable 2008 period primarily due to normal production declines at our Ship Shoal 72 and Turtle Bayou Fields, which produce approximately half of our total oil production. Partially offsetting these declines was the inception of production at our Pelican Point prospect in May 2008, which accounted for approximately 13% of our total oil production during the nine-month period ended September 30, 2009.
Gas production during the nine-month period ended September 30, 2009 increased 12% from the comparable period in 2008. The increase in gas production was primarily the result of our drilling success during 2008 in our longer life basins, where the production is primarily natural gas, as well as discoveries at our Pelican Point and The Bluffs prospects in South Louisiana. Overall, production during the first nine months of 2009 was 9% higher than the 2008 period.
Although we have achieved Company records for production in each of the last five years, in response to low commodity prices, we have reduced our 2009 drilling activities. As a result, we expect that production during the fourth quarter of 2009 will decline, as compared to the volumes produced during the fourth quarter of 2008.
Prices. Including the effects of our hedges, average oil prices per barrel for the quarter and nine months ended September 30, 2009 were $75.32 and $64.41, respectively, as compared to $113.79 and $105.77, respectively, for the 2008 periods. Average gas prices per Mcf for the quarter and nine months ended September 30, 2009 were $5.56 and $5.67, respectively, as compared to $8.50 and $8.87 for the respective 2008 periods. Stated on an Mcfe basis, unit prices received during the quarter and nine months ended September 30, 2009 were 34% and 38% lower than the prices received during the comparable 2008 periods. Revenue. Including the effects of hedges, oil and gas sales during the quarter and nine months ended September 30, 2009 decreased 35% and 32% to $50,182,000 and $164,792,000, respectively, as compared to oil and gas sales of $76,987,000 and $242,420,000 during the 2008 periods. The decreases in sales during the 2009 periods were primarily the result of lower commodity prices. Further declines in commodity prices would continue to negatively impact our future oil and gas sales.

Expenses. Lease operating expenses for the three- and nine-month periods ended September 30, 2009 decreased to $9,665,000 and $29,171,000, respectively, as compared to $11,721,000 and $31,818,000, respectively, during the 2008 periods. Per unit operating expenses totaled $1.21 and $1.09, per Mcfe during the three- and nine-month periods of 2009, respectively, as compared to $1.46 and $1.31 per Mcfe during the 2008 periods. The decreases in lease operating expenses were primarily due to the decline in costs of services and materials in the markets in which we operate as the demand for such materials and services has weakened as a result of the substantial decline in commodity prices and the overall condition of the oil and gas industry and the global economy.
Production taxes during the quarter and nine months ended September 30, 2009 totaled $176,000 and $3,196,000, respectively, as compared to $3,060,000 and $9,489,000 during the 2008 periods. During the third quarter of 2009, we filed for a production tax refund in the amount of $1,144,000 at our Pelican Point prospect as the well qualified for a deep well severance tax exemption for a period of 24-months from the initial production date of May 2008. In addition, we received a production tax refund of $570,000 during the second quarter of 2009 related to certain of our horizontal wells in Oklahoma that qualify for a 48-month production tax exemption. Finally, the impact of lower commodity prices realized for the production from our Oklahoma, Arkansas and Texas properties contributed to the decline in production taxes during the 2009 periods. Partially offsetting these decreases was a 15% increase in the Louisiana gas severance tax rate effective July 1, 2009.
General and administrative expenses during the quarter and nine months ended September 30, 2009 decreased 28% and 27% to $4,142,000 and $13,164,000, respectively, as compared to expenses of $5,720,000 and $18,036,000 during the comparable 2008 periods. We capitalized $1,916,000 and $6,143,000, respectively, of general and administrative costs during the three- and nine-month periods ended September 30, 2009 and $2,628,000 and $9,155,000 during the comparable 2008 periods. The declines in general and administrative expenses during the 2009 periods were in part due to lower non-cash share based compensation during the three- and nine-month periods ended September 30, 2009, as compared to the corresponding 2008 periods. In addition, during May 2008, we incurred compensation expense of approximately $2.5 million, or approximately $1.2 million net of capitalization, related to the election to pay employee taxes on the vesting of certain restricted stock grants. There was no similar expense incurred during 2009. Overall, we expect that general and administrative costs during the fourth quarter of 2009 will approximate third quarter 2009 amounts.
Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the quarter and nine months ended September 30, 2009 totaled $17,643,000, or $2.21 per Mcfe, and $67,268,000, or $2.52 per Mcfe, respectively, as compared to $33,420,000, or $4.16 per Mcfe, and $93,408,000, or $3.84 per Mcfe, during the 2008 periods. The declines in our DD&A per Mcfe were the result of the ceiling test write-down of a substantial portion of our proved oil and gas properties during 2008 and the first quarter of 2009 as a result of lower commodity prices.
The prices of oil and natural gas used in computing our estimated proved reserves at March 31, 2009 had a negative impact on our proved reserves from certain of our longer-life properties and reduced the estimated future net cash flows from our proved reserves. As a result, we recorded a non-cash ceiling test write-down of our oil and gas properties at March 31, 2009 totaling $103,582,000. See Note 8, "Ceiling Test" for further discussion of the ceiling test.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $3,531,000 and $10,095,000, respectively, during the quarter and nine months ended September 30, 2009 as compared to $1,609,000 and $6,498,000 during the 2008 periods. The increases in interest expense during the 2009 periods are due to the increase in bank debt outstanding. We capitalized $2,113,000 and $6,350,000 of interest during the three- and nine-month periods of 2009 and $3,190,000 and $7,991,000 during the respective 2008 periods. During September and October 2009, we repaid a total of $81 million of bank borrowings. As a . . .