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.
Disclosure requirements under Staff Accounting Bulletin 113 ("SAB 113") 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 rules also allow companies the option to disclose probable and possible reserves in addition to the existing requirement to disclose proved reserves. The 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. Pricing is based on a 12-month average price using beginning of the month pricing during the 12-month period prior to the ending date of the balance sheet to report oil and natural gas reserves. In addition, the 12-month average will also be used to measure ceiling test impairments and to compute depreciation, depletion and amortization. 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 oil and gas properties, whether or not being amortized currently, 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, including the effect of cash flow hedges in place, 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. At September 30, 2012, the prices used in computing the estimated future net cash flows from our estimated proved reserves, including the effect of hedges in place at that date, averaged $2.22 per Mcf of natural gas, $104.83 per barrel of oil, and $7.44 per Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of our longer-lived estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of $35.4 million and $109.0 million during the three and nine months ended September 30, 2012, respectively. Our cash flow hedges in place at September 30, 2012 decreased the ceiling test write-down by approximately $2.1 million.

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 further 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. Derivative Instruments
The estimated fair values of our commodity derivative instruments are recorded in the consolidated balance sheet. The changes in fair value of those derivative instruments that qualify for hedge accounting treatment are recorded in other comprehensive income (loss) until the hedged oil, natural gas or Ngl 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 (expense).
Our hedges are specifically referenced to NYMEX prices for oil and natural gas and OPIS Mt. Bellevue prices for Ngls. 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 and OPIS 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 or OPIS prices at which the hedges will be settled. At September 30, 2012, our derivative instruments, with the exception of our 2013 three-way collar, were designated effective cash flow hedges.
Estimating the fair value of derivative instruments requires valuation calculations incorporating estimates of future NYMEX or OPIS prices, discount rates and price movements. As a result, we calculate 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.

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 September 30,          Nine Months Ended September 30,
                                              2012                2011                  2012                  2011
Production:
Oil (Bbls)                                       122,645          130,144               379,958                445,457
Gas (Mcf)                                      6,888,569        6,073,776            20,563,350             17,847,061
Ngl (Mcfe)                                       894,138          584,786             2,250,569              1,658,323
Total Production (Mcfe)                        8,518,577        7,439,426            25,093,667             22,178,126
Sales:
Total oil sales                        $      13,287,548     $ 13,508,377     $      41,627,602          $  46,403,861
Total gas sales                               15,583,994       19,865,595            46,321,605             60,481,702
Total ngl sales                                5,041,274        5,606,335            15,336,515             15,560,225
Total oil and gas sales                $      33,912,816     $ 38,980,307     $     103,285,722          $ 122,445,788
Average sales prices:
Oil (per Bbl)                          $          108.34     $     103.80     $          109.56          $      104.17
Gas (per Mcf)                                       2.26             3.27                  2.25                   3.39
Ngl (per Mcfe)                                      5.64             9.59                  6.81                   9.38
Per Mcfe                                            3.98             5.24                  4.12                   5.52

The above sales and average sales prices include increases to revenue related to the settlement of gas hedges of $1,482,000 and $478,000, oil hedges of $491,000 and $178,000 and Ngl hedges of $312,000 and zero for the three months ended September 30, 2012 and 2011, respectively. The above sales and average sales prices include increases (reductions) to revenue related to the settlement of gas hedges of $6,867,000 and $864,000, oil hedges of $853,000 and ($211,000) and Ngl hedges of $544,000 and zero for the nine months ended September 30, 2012 and 2011, respectively.
Net income (loss) available to common stockholders totaled ($38,639,000) and $3,727,000 for the quarters ended September 30, 2012 and 2011, respectively, while net income (loss) available to common stockholders totaled ($111,767,000) and $2,579,000 for the nine months ended September 30, 2012 and 2011, respectively. The primary fluctuations were as follows:
Production Total production increased 15% and 13%, respectively, during the three and nine month periods ended September 30, 2012 as compared to the 2011 periods. Gas production during the three and nine month periods ended September 30, 2012 increased 13% and 15%, respectively, from the comparable periods in 2011. The increase in gas production was primarily the result of the success of our drilling program in the Woodford Shale in Oklahoma, the Carthage field in East Texas, and the La Cantera field in South Louisiana. Gas production also increased at our West Cameron Block 402 well due to a successful recompletion during the fourth quarter of 2011. As a result of continued drilling in our longer-life basins, we expect our average daily gas production in 2012 to increase as compared to 2011.
Oil production during the three and nine month periods ended September 30, 2012 decreased 6% and 15%, respectively, from the 2011 periods due primarily to continued normal production declines in our onshore Louisiana and offshore Gulf of Mexico fields. Partially offsetting these decreases were increases from the inception of production from our La Cantera field during March 2012 and our Eagle Ford Shale wells during the second quarter of 2011. Although we expect to increase oil production from drilling operations in the Mississippian Lime, the Eagle Ford Shale and our La Cantera field, such increase is not expected to completely offset normal declines in the Gulf Coast area. As a result, we expect our average daily oil production during 2012 to decrease as compared to 2011. Ngl production during the three and nine month periods ended September 30, 2012 increased 53% and 36%, respectively, from the 2011 periods due to the inception of production from our La Cantera field and the liquids rich portion of our Oklahoma properties as well as an increase in production at our Carthage field in East Texas. As a result of ongoing drilling in our Texas, Oklahoma and Gulf Coast assets, we expect our daily Ngl production in 2012 to increase significantly as compared to 2011.
Prices Including the effects of our hedges, average gas prices per Mcf for the three and nine month periods ended September 30, 2012 were $2.26 and $2.25, respectively, as compared to $3.27 and $3.39, respectively, for the 2011 periods. Average oil prices per Bbl for the three and nine months ended September 30, 2012 were $108.34 and $109.56, respectively, as compared to $103.80 and $104.17, respectively, for the 2011 periods and average Ngl prices per Mcfe were $5.64 and $6.81, respectively, for the three

and nine months ended September 30, 2012, as compared to $9.59 and $9.38, respectively, for the 2011 periods. Stated on an Mcfe basis, unit prices received during the three and nine months ended September 30, 2012 were 24% and 25% lower, respectively, than the prices received during the comparable 2011 periods.
Revenue Including the effects of hedges, oil and gas sales during the three months ended September 30, 2012 decreased 13% to $33,913,000, as compared to oil and gas sales of $38,980,000 during the 2011 period. Including the effects of hedges, oil and gas sales during the nine months ended September 30, 2012 decreased 16% to $103,286,000, as compared to oil and gas sales of $122,446,000 during the 2011 period. The decreased revenue during 2012 was primarily the result of lower natural gas prices as well as reduced oil production during the period.
Expenses Lease operating expenses for the three and nine months ended September 30, 2012 totaled $9,658,000 and $28,408,000, respectively, as compared to $10,376,000 and $30,085,000 during the 2011 periods. Per unit lease operating expenses totaled $1.13 per Mcfe during each of the three and nine month periods ended September 30, 2012 as compared to $1.39 and $1.36 per Mcfe during the 2011 periods. Per unit lease operating expenses decreased primarily due to the increase in overall produced volumes during the period as well as lower absolute costs due to cost savings primarily associated with our Woodford saltwater disposal systems.
Production taxes for the three and nine months ended September 30, 2012 totaled $880,000 and $112,000, respectively, as compared to $1,446,000 and $2,070,000 during the 2011 periods. The decrease during during the nine month period of 2012 was the result of recording a receivable of $2,717,000 during June 2012 for refunds relative to severance tax previously paid on our Oklahoma horizontal wells that we expect to receive over the next three years.
General and administrative expenses during the three and nine months ended September 30, 2012 totaled $5,963,000 and $17,541,000, respectively, as compared to $4,990,000 and $13,668,000 during the 2011 periods. Included in general and administrative expenses was share-based compensation expense as follows (in thousands):

                                              Three Months Ended
                                                 September 30,          Nine Months Ended September 30,
                                              2012           2011              2012             2011
Stock options:
Incentive Stock Options                   $       211     $     122     $            646     $     279
Non-Qualified Stock Options                       181           192                  509           526
Restricted stock                                1,379           754                4,454         2,180
Share based compensation                  $     1,771     $   1,068     $          5,609     $   2,985

General and administrative expenses increased 19% and 28% during the three and nine months ended September 30, 2012 as compared to the comparable periods of 2011 primarily due to increased non-cash share-based compensation expense during the 2012 periods. We capitalized $3,276,000 and $9,582,000 of general and administrative costs during the three and nine month periods ended September 30, 2012, respectively, and we capitalized $2,670,000 and $8,179,000 during the comparable 2011 periods. General and administrative expenses in 2012 are expected to be higher than in 2011 as a result of increased non-cash share based compensation expense and expansion of staffing as we develop the Mississippian Lime assets.
Depreciation, depletion and amortization ("DD&A") expense on oil and gas properties for the three and nine months ended September 30, 2012 totaled $14,736,000, or $1.73 per Mcfe, and $45,203,000, or $1.80 per Mcfe, respectively, as compared to $14,412,000, or $1.94 per Mcfe, and $42,616,000, or $1.92 per Mcfe, during the comparable 2011 periods. The decrease in the per unit DD&A rate is primarily the result of positive drilling results in our La Cantera field, Woodford Shale and East Texas drilling programs as well as the write-down of a portion of our evaluated oil and gas properties during the first half of 2012.
At September 30, 2012, the prices used in computing the estimated future net cash flows from our estimated proved reserves, including the effect of hedges in place at that date, averaged $2.22 per Mcf of natural gas, $104.83 per barrel of oil, and $7.44 per Mcfe of Ngl. As a result of lower natural gas prices and their negative impact on certain of our longer-lived estimated proved reserves and estimated future net cash flows, we recognized ceiling test write-downs of $35,391,000 and $108,987,000 during the three and nine months ended September 30, 2012, respectively. Our cash flow hedges in place at September 30, 2012 decreased the ceiling test write-down by approximately $2.1 million. We also recognized a ceiling test write-down of $18,907,000 during the nine months ended September 30, 2011.
Interest expense, net of amounts capitalized on unevaluated properties, totaled $2,338,000 and $7,021,000 during the three and nine months ended September 30, 2012, respectively, as compared to $2,299,000 and $7,248,000 during the 2011 periods. During

the three and nine months periods ended September 30, 2012, our capitalized interest totaled $1,869,000 and $5,452,000, respectively, as compared to $1,851,000 and $5,111,000 during the 2011 periods.
Income tax expense (benefit) during the three and nine months ended September 30, 2012 totaled $1,435,000 and $1,496,000, respectively, as compared to ($265,000) and ($594,000) during the 2011 periods. We typically provide for income taxes at a statutory rate of 35% adjusted for permanent differences expected to be realized, primarily statutory depletion, non-deductible stock compensation expenses and state income taxes.
As a result of the ceiling test write-downs recognized, we have incurred a cumulative three-year loss. Because of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, we assessed the realizability of our deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, we established a valuation allowance for a portion of our deferred tax asset. The valuation allowance was $40,843,000 as of September 30, 2012. Liquidity and Capital Resources
We have financed our acquisition, exploration and development activities to date principally through cash flow from operations, bank borrowings, second lien term credit facilities, issuances of equity and debt securities, joint ventures and sales of assets. At September 30, 2012, we had a working capital deficit of $49 million compared to a deficit of $14 million at December 31, 2011. The increase in our working capital deficit is primarily the result of our increased operational activities as our capital expenditures during the first nine months of 2012 exceeded our cash flow from operations. Since we operate the majority of our drilling activities, we have the ability to reduce our capital expenditures to manage our working capital deficit and liquidity position. To the extent our capital expenditures during the fourth quarter of 2012 exceed our cash flow and cash on hand, we plan to utilize available borrowings under the bank credit facility or proceeds from the potential sale of assets to fund a portion of our drilling budget.
Prices for oil and natural gas are subject to many factors beyond our control such as weather, the overall condition of the global financial markets and economies, relatively minor changes in the outlook of supply and demand, and the actions of OPEC. Oil and natural gas prices have a significant impact on our cash flows available for capital expenditures and our ability to borrow and raise additional capital. The amount we can borrow under our bank credit facility is subject to periodic re-determination based in part on changing expectations of future prices. Lower prices may also reduce the amount of oil . . .