General

We are an independent oil and natural gas exploration and production company focused on the development of the Cotton Valley group of formations, specifically the Cotton Valley Sands layer in the Schuler formation and the Upper Bossier, Middle Bossier and Haynesville/Lower Bossier layers of Bossier formation (the "Haynesville/Bossier Shale" or "H/B") in the Sabine Uplift, of the Carthage, North Field of Harrison and Panola counties of East Texas (our "core area"). As of September 30, 2009, we had identified 768 gross (520 net) potential undrilled Haynesville/Bossier Shale horizontal well locations across our acreage, assuming 80-acre well spacing, and approximately 2,000 net potential undrilled Cotton Valley Sands drilling locations across our acreage, assuming 20-acre well spacing. We currently have 401 gross (251 net) producing wells, of which 10 gross (9.9 net) are Haynesville/Bossier Shale horizontal wells, 325 gross (187.9 net) are Cotton Valley Sands wells, and 47 gross (39.5 net) Travis Peak/Hosston Sands & Pettit producers. These multiple resource layers provide high probability and the potential for repeatable, organic growth. We intend to use up to four operated drilling rigs to develop this contiguous, multi-layer gas resource play. We have invested over $100 million in infrastructure and operate over 81% of our reserves.

Our strategy is to grow shareholder value through Haynesville/Bossier Shale horizontal well development as well as Cotton Valley Sand wells, to continue acreage acquisitions in our core area, to focus on operational growth in and around our core area, and to convert our natural gas reserves to proved reserves, while maintaining balanced prudent financial management. To date, we have experienced a 100% success rate and have maintained low finding and development costs while primarily drilling Cotton Valley Sand vertical wells. Almost 100% of our 2009 capital expenditure budget is focused on our H/B horizontal drilling program.

The table below summarizes information concerning our activities in the three and nine months ended September 30, 2009 compared to the three and nine months ended September 30, 2008.

Summary Operating Data



                                                     Three Months Ended        Nine Months Ended
                                                        September 30,            September 30,
                                                      2008          2009       2008          2009
Production:
Oil (MBbls)                                                51           28        150            91
Natural gas (MMcf)                                      3,204        3,322      8,733         9,477
Gas equivalent production (MMcfe)                       3,513        3,491      9,632        10,024
Average daily (MMcfe)                                    38.2         37.9       35.2          36.7

Average Sales Price:

Oil (per Bbl)
Wellhead price                                     $   114.97      $ 63.93   $ 110.91      $  51.18
Effect of hedges                                       (15.14 )      16.89     (11.97 )       21.11

Total                                              $    99.83      $ 80.82   $  98.94      $  72.29

Natural gas (per Mcf)
Wellhead price                                     $    10.42      $  3.44   $  10.61      $   3.63
Effect of hedges                                        (0.66 )       2.82      (0.67 )        2.93

Total                                              $     9.76      $  6.26   $   9.94      $   6.56
Average sales price (per Mcfe)                     $    10.36      $  6.61   $  10.55      $   6.86
Operating and Overhead Costs (per Mcfe):
Lease operating expenses                           $     1.17      $  0.78   $   1.11      $   0.86
Production and severance taxes                           0.47         0.08       0.49         (0.11 )
General and administrative                               1.31         1.38       1.24          1.45

Total                                              $     2.95      $  2.24   $   2.84      $   2.20

Cash Operating Margin (per Mcfe)                   $     7.41      $  4.37   $   7.71      $   4.66


Other (per Mcfe):
Depreciation, depletion and amortization-oil and
natural gas properties                             $     2.00      $  1.70   $   2.01      $   1.86

Results of Operations-Three Months Ended September 30, 2009 Compared to Three Months Ended September 30, 2008

Oil and Natural Gas Sales. Oil and natural gas sales in the three months ended September 30, 2009 decreased 37% to $23.1 million compared to the three months ended September 30, 2008. This decrease was due to a 36% decrease in the average realized price of oil and natural gas, net of hedging activities. The average price per barrel of oil and Mcf of natural gas received (net of hedging) in the three months ended September 30, 2009 was $80.82 and $6.26, respectively, compared to $99.83 and $9.76, respectively, in the three months ended September 30, 2008. Production of oil for the three months ended September 30, 2009 decreased to 28 MBbls compared to 51 MBbls for the three months ended September 30, 2008, a decrease of 45%. The decrease in oil production is due to the natural decline in the Company's Cotton Valley Sand vertical well production which has historically provided most of the Company's oil production. H/B horizontal wells typically do not have oil production. Natural gas production for the three months ended September 30, 2009 increased to 3,322 MMcf compared to 3,204 MMcf for the three months ended September 30, 2008, an increase of 4%. The increase in natural gas production resulted from production related to nine producing H/B horizontal wells that were on-line during 2009. Production from H/B horizontal wells accounted for 53% of total production in the third quarter of 2009.

In the three months ended September 30, 2009, as a result of hedging activities, we recognized an increase in oil and natural gas sales of $0.5 million and $9.3 million, respectively, compared to a decrease in oil and natural gas sales of $0.8 million and $2.1 million, respectively, in the third quarter of 2008. In the third quarter of 2009, hedging increased the average natural gas and oil sales price by $2.82 per Mcf and $16.89 per Bbl compared to a decrease in natural gas sales price of $0.66 per Mcf and $15.14 per Bbl in the third quarter of 2008.

Lease Operations. Lease operations expense decreased $1.4 million, or 34.1%, in the three months ended September 30, 2009 to $2.7 million, compared to the three months ended September 30, 2008. Lease operations expense on an equivalent unit of production basis decreased $0.39 per Mcfe in the three months ended September 30, 2009 to $0.78 per Mcfe, compared to the three months ended September 30, 2008. The decrease in lease operating expenses on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented during 2009. During the three months ended September 30, 2008, the Company incurred additional lease operating expenses related to several well workovers and road and compressor repairs. With little to no incremental increase in lease operating costs from a typical Cotton Valley vertical well, the significantly larger amount of production from a typical H/B horizontal well results in lower per unit lease operating costs.

Production and Severance Taxes. Production and severance taxes decreased 83% from $1.7 million in the three months ended September 30, 2008 to $0.3 million in the three months ended September 30, 2009. Production and severance tax expense decreased in comparison to the third quarter of 2008 due to a decrease in oil and natural gas prices between the two periods and the fact that more producing wells in the third quarter of 2009 have received production and severance tax exemptions. Upon approval by the State of Texas, certain wells, including our H/B horizontal wells, are exempt from severance taxes for a period of ten years and we expect this to continue to reduce our expense going forward.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense decreased $0.5 million, or 5%, to $7.8 million in the three months ended September 30, 2009 compared to the three months ended September 30, 2008. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.70 per Mcfe in the three months ended September 30, 2009 compared to $2.00 per Mcfe in the three months ended September 30, 2008. This decrease is due primarily to a lower cost basis in oil and gas properties subject to amortization due to previously recorded impairment charges as a result of lower oil and natural gas prices at year end 2008 and March 31, 2009.

General and Administrative Expense. General and administrative expense for the three months ended September 30, 2009 was $4.8 million compared to $4.6 million for the three months ended September 30, 2008, an increase of $0.2 million, or 5%. General and administrative expense per equivalent unit of production was $1.38 per Mcfe for the three months ended September 30, 2009 compared to $1.31 per Mcfe for the three months ended September 30, 2008. A significant portion of the Company's general and administrative expense is related to non-cash compensation expense. Non-cash compensation expense for the three months ended September 30, 2009 and 2008 was $1.4 million or 29% of total general and administrative expenses and $1.0 million or 21% of total general and administrative expenses, respectively. General and administrative expenses have not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature. The Company expects general and administrative expenses on a per Mcfe basis to decrease as production increases.

Interest. Interest expense for the three months ended September 30, 2009 was $4.2 million compared to approximately $3.6 million for the three months ended September 30, 2008. This increase is primarily due to a greater amount of outstanding debt during the three months ended September 30, 2009. Interest expense for the three months ended September 30, 2008 and 2009 includes non-cash interest expense of $757,000 and $846,000, respectively related to the amortization of the convertible notes and the adoption of FASB ASC 470-20, Accounting for Convertible Debt Instruments that May Be Settled in Cash Upon Conversion.

Income Taxes. Income tax for the three months ended September 30, 2009 was an expense of $4.5 million as compared to an expense of $4.7 million in the three months ended September 30, 2008. The tax expense for the three months ended September 30, 2009 was due to $4.6 million of deferred tax expense relating to a valuation allowance for federal net operating loss carryforwards that increased our tax expense.

Results of Operations-Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

Oil and Natural Gas Sales. Oil and natural gas sales in the nine months ended September 30, 2009 decreased 32% to $68.7 million compared to the nine months ended September 30, 2008. This decrease was due to a 35% decrease in the average realized price of oil and natural gas, net of hedging activities, partially offset by a 4% increase in production. The average price per barrel of oil and Mcf of natural gas received (net of hedging) in the nine months ended September 30, 2009 was $72.79 and $6.56, respectively, compared to $98.94 and $9.94, respectively, in the nine months ended September 30, 2008. Production of oil for the first nine months of 2009 decreased to 91MBbls compared to 150 MBbls for the first nine months of 2008, a decrease of 39%. The decrease in oil production is due to the natural decline in the Company's Cotton Valley Sand vertical well production which has historically provided most of the Company's oil production. H/B horizontal wells typically do not have oil production. Natural gas production for the first nine months of 2009 increased to 9,477 MMcf compared to 8,733 MMcf for the first nine months of 2008, an increase of 9%. The increase in natural gas production resulted from production related to nine producing H/B horizontal wells that were on-line during the first nine months of 2009. Production from H/B horizontal wells accounted for 30% of total production in the first nine months of 2009.

In the nine months ended September 30, 2009, as a result of hedging activities, we recognized an increase in oil and natural gas sales of $1.9 million and $27.7 million, respectively, compared to a decrease in oil and natural gas sales of $1.8 million and $5.8 million, respectively, in the first nine months of 2008. In the first nine months of 2009, hedging increased the average natural gas and oil sales price by $2.93 per Mcf and $21.11 per Bbl compared to a decrease in natural gas sales price of $0.67 per Mcf and $11.97 per Bbl in the first nine months of 2008.

Lease Operations. Lease operations expense decreased $2.1 million, or 19%, in the nine months ended September 30, 2009 to $8.6 million, compared to $10.7 million in the nine months ended September 30, 2008. Lease operations expense on an equivalent unit of production basis decreased $0.25 per Mcfe in the nine months ended September 30, 2009 to $0.86 per Mcfe, compared to the nine months ended September 30, 2008. The decrease in lease operating expenses on an equivalent unit basis resulted from an increase in H/B horizontal well production and cost control measures implemented during the first nine months of 2009. With little to no incremental increase in lease operating costs from a typical Cotton Valley vertical well, the significantly larger amount of production from a typical H/B horizontal well will result in lower per unit lease operating costs.

Production and Severance Taxes. As a result of the recognition of severance tax refunds of approximately $2.0 million in the nine months ended September 30, 2009, production and severance taxes decreased 123% from an expense of $4.7 million in the nine months ended September 30, 2008 to income of $1.1 million in the nine months ended September 30, 2009. Upon approval by the State of Texas, certain wells, including our H/B horizontal wells, are exempt from severance taxes for a period of ten years and we expect this to reduce our expense going forward. Excluding the production and severance tax refunds received in the first nine months of 2009, production and severance tax expense decreased in comparison to the first nine months of 2008 due to a decrease in oil and natural gas prices between the two periods and the fact that more producing wells in the first nine months of 2009 have received the production and severance tax exemptions.

Depreciation, Depletion and Amortization. Depreciation, depletion and amortization expense increased $1.6 million, or 7%, to $24.4 million in the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. The increase in expense is due to the increase in depreciation related to property and equipment. The oil and gas properties depreciation, depletion and amortization rate per equivalent unit of production was $1.86 per Mcfe in the nine months ended September 30, 2009 compared to $2.01 per Mcfe in the nine months ended September 30, 2008. This decrease in the rate per Mcfe is due to a lower cost basis in oil and gas properties subject to amortization due to previously recorded impairment charges as a result of lower oil and gas prices at year end 2008 and at March 31, 2009.

Impairment and other writedowns. As a result of lower oil and natural gas prices from year-end 2008, we recognized an impairment charge on oil and gas properties of $180.3 million in the nine months ended September 30, 2009. In addition, as a result of the decline in oil and natural gas related material costs, we recognized a writedown of $6.2 million on pipeline related inventories in this nine month period. The Company may be required to recognize additional impairment charges or writedowns in future reporting periods if market prices for oil or natural gas and material costs continue to decline.

General and Administrative Expense. General and administrative expense for the nine months ended September 30, 2009 was $14.6 million compared to $12.0 million for the nine months ended September 30, 2008, an increase of $2.6 million, or 22%. A $1.2 million allowance for bad debt was recognized in the second quarter of 2008 related to the bankruptcy of one of our crude oil purchasers. The allowance was subsequently adjusted downward in the third quarter of 2008 to $748,000. However, due to an unfavorable bankruptcy court ruling, we recognized $0.5 million additional bad debt expense in the second quarter of 2009. The reduction in bad debt expense between 2008 and 2009 was offset by an increase in non-cash compensation expense and an increase in administrative and supervisory personnel. General and administrative expense per equivalent unit of production was $1.45 per Mcfe for the nine months ended September 30, 2009 compared to $1.24 per Mcfe for the comparable period in 2008. Excluding the provisions for bad debt expense and non-cash compensation, general administrative expense for the nine months ended September 30, 2008 and 2009 would have been $0.95 per Mcfe and $1.04 per Mcfe, respectively. General and administrative expense has not historically varied in direct proportion to oil and natural gas production because certain types of general and administrative expenses are non-recurring or fixed in nature. In the second half of 2008, the Company added key employees to execute an H/B horizontal drilling program. As a result, personnel costs have increased in comparison to the first nine months of 2008. The Company expects general and administrative expenses on a per Mcfe basis to decrease as production increases.

Interest. Interest expense for the nine months ended September 30, 2009 was $12.1 million compared to $10.3 million for the nine months ended September 30, 2008. This increase is primarily due to a greater amount of outstanding debt during the nine months ended September 30, 2009. Interest expense for the nine months ended September 30, 2008 and 2009 includes non-cash interest expense of $1.9 million and $2.7 million, respectively related to the amortization of the 5.00% convertible notes and the adoption of FASB ASC 470-20, Accounting for Convertible Debt Instruments that May Be Settled in Cash Upon Conversion.

Income Taxes. Income tax for the nine months ended September 30, 2009 was a benefit of $43.7 million as compared to an expense of $13.2 million in the nine months ended September 30, 3008. The effective tax rates for the nine months ended September 30, 2008 and 2009 were 32% and 24%, respectively. The decrease in the effective tax rate in the nine months ended September 30, 2009 was due to $17.3 million of deferred tax expense relating to a valuation allowance for federal net operating loss carryforwards that reduced our tax benefit. Excluding the deferred tax expense for the valuation allowance, our effective income tax rate would have been approximately 34%.

Net Income and Net Income Per Share

For the three months ended September 30, 2009 and 2008, we reported a net loss of $2.8 million and net income of $9.6 million, respectively, a decrease of 129%. Net loss applicable to common stock for the three months ended September 30, 2009 was $3.9 million compared to net income of $8.5 million for the three months ended September 30, 2008, a decrease of 146%. Net loss per basic and fully diluted share was $0.19 for the third quarter of 2009 compared to net income of $0.57 and $0.50 respectively, per basic and fully diluted share for the third quarter of 2008. Weighted average fully-diluted shares outstanding increased by 24% from 17,099,929 shares in the third quarter of 2008 to 21,160,616 shares in the third quarter of 2009.

For the nine months ended September 30, 2009 and 2008, we reported a net loss of $135.4 million and net income of $28.2 million, a decrease of 580%. Net income
(loss) applicable to common stock for the nine months ended September 30, 2009 and 2008 was $(138.9) million and $24.7 million, respectively, a decrease of 662%. Net income (loss) per basic and fully diluted share was $(7.61) and $(7.60) respectively, for the nine months of 2009 compared to $1.79 and $1.62 respectively, for the nine months of 2008. Weighted average fully-diluted shares outstanding increased by 20% from 15,224,742 shares in the first nine months of 2008 to 18,278,639 shares in the first nine months of 2009.

Capital Resources and Liquidity

Our business is capital intensive. Our ability to grow our reserve base is dependent upon our ability to obtain outside capital and generate cash flows from operating activities to fund our drilling and capital expenditures. Our cash flows from operating activities are substantially dependent upon crude oil and natural gas prices, and significant decreases in market prices of crude oil or natural gas could result in reductions of cash flow and affect our drilling and capital expenditure plan. To mitigate a portion of our exposure to fluctuations in commodity prices, we have entered into crude oil and natural gas swaps, collars, and put spreads.

We continually review our drilling and capital expenditure plans and may change the amount we spend based on industry conditions and the availability of capital. In response to the changing economic environment, we have revised our capital expenditure budget throughout 2009, and we now expect expenditures of approximately $175.0 million for 2009, a decrease from $220 million budgeted at the beginning of the year. In the nine months ended September 30, 2009, our capital expenditures were $138.3 million of which $82.3 million was for drilling and completing H/B horizontal wells; $9.2 million was for rig delay fees; $9.3 million on Cotton Valley and Travis Peak drilling and other drilling related expenditures including tubular inventory and $37.5 million was related to leasehold and infrastructure costs. In the nine months ended September 30, 2009, we had nine H/B horizontal well completions.

In the last three months of 2009, we expect to have capital expenditures of approximately $36.7 million primarily related to drilling and completing H/B horizontal wells. Our current capital expenditure budget for the rest of 2009 assumes two operated rigs drilling H/B horizontal wells, the most recent of which we activated on October 15, 2009. We do not expect to have significant infrastructure or inventory expenditures in the last three months of 2009. We expect to complete 2 wells drilled in the second and third quarter, drill and complete 2 H/B horizontal wells and begin drilling 2 H/B horizontal wells in the fourth quarter of 2009.

During 2009, we have accessed the capital markets and sold non-core assets to fund our H/B horizontal drilling program. In May 2009, we were successful in raising $65 million from the sale of 5.75 million shares of common stock. In October 2009, we were again successful in raising $190 million, before estimated expenses of $9 million, from the sale of 6.95 million shares of common stock and the issuance of $86 million aggregate principal amount of 4.50% convertible notes. In addition to these capital market transactions, we received $36 million in November 2009 from the partial monetization of our mid-stream assets in the Endeavor Gathering transactions. We expect that this capital raised during 2009 will be sufficient to fund a four rig drilling program through the point at which our discretionary cash flows will exceed our capital expenditures. We will continually adjust our capital expenditures based on the current commodity price environment to ensure that we have adequate liquidity in cash and/or with availability under our revolving bank credit facility. We anticipate using various derivative contracts such as puts, put spreads, and collars to mitigate natural gas and crude oil price risk on 60% to 80% of our expected production over a rolling 36 month period.

Anticipated 2010 capital expenditure guidance ranges from $190 million for a three H/B Hz rig drilling program to $240 million if the fourth contracted rig begins H/B Hz drilling in late March 2010 as currently scheduled. Due to the recent capital raising activities exceeding the original offering amounts, we have the potential to increase the 2010 capital expenditure guidance by approximately $25 million, if we elect to participate in additional proposed non-operated wells.

Cash Flow-Nine Months Ended September 30, 2009 Compared to Nine Months Ended September 30, 2008

In the nine months ended September 30, 2009 and 2008, we spent $138.3 million and $216.1 million, respectively, for oil and gas acquisitions and development activities, including the acquisition of property and equipment. These investments were funded during the nine months ended September 30, 2009 by cash flow from operations, borrowing under our revolving bank credit facility and proceeds from the issuance of common stock and 4.50% convertible notes. Cash flow provided by operating activities in the nine months ended September 30, 2009 and 2008 was $31.7 million and $58.8 million, respectively. The decrease in net cash provided by operating activities is due to a decrease in income from operations caused by lower oil and natural gas prices.

Revolving Bank Credit Facility and Other Debt

Revolving Bank Credit Facility. We have a secured revolving bank credit facility, which matures on July 15, 2011 and provides for a line of credit of up to $250 million (the "commitment"), subject to a borrowing base which is based on a periodic evaluation of oil and gas reserves ("borrowing base"). The amount of credit available at any one time under the credit facility is the lesser of the borrowing base or the amount of the commitment. On June 5, 2009, we completed our semi-annual redetermination of our revolving credit facility borrowing base. As a result, the borrowing base was amended to $175 million, as compared to the prior level of $190 million. Also in connection with this amendment, the interest rate applicable to borrowings under our revolving bank credit facility was increased and we agreed to an additional financial covenant relating to our ratio of total debt to EBITDA. At September 30, 2009, the amount outstanding under our revolving bank credit facility was $124 million.

Effective as of October 17, 2009, we amended the terms of our revolving bank credit facility to document our lenders' consent to the Endeavor Gathering joint venture transaction. In addition, this amendment decreased our borrowing base under the revolving bank credit facility from $175 million to $140 million upon the closing of the Endeavor Gathering joint venture transaction effective on November 1, 2009, based on the release by the lenders of the contributed assets from the collateral pledged in support of the indebtedness under the revolving credit facility. As part of the amendment, we also agreed to the inclusion of certain covenants in the revolving credit facility that prohibit the creation of certain debt or the creation of incurrence of certain liens by Endeavor . . .