The following discussion of operations for the three and six months ended June 30, 2009 and 2008 should be read in conjunction with our condensed consolidated financial statements and the notes thereto included in this Form 10-Q and with the consolidated financial statements, notes and management's discussion and analysis included in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2008.

Overview

We are an independent energy company engaged in the exploration, development and production of predominately natural gas properties located onshore in the United States. Our properties are primarily located in Louisiana, Texas, Arkansas and Oklahoma. We organize our operations into two principal regions: the Mid-Continent, which includes our Louisiana and Arkansas properties; and the Western, which includes our Texas and Oklahoma properties.

Historically, we have grown through acquisitions of proved reserves and undeveloped acreage, with a focus on properties within our core operating areas which we believe have significant development and exploration opportunities and where we can apply our technical experience and economies of scale to increase production and proved reserves while lowering lease operating costs. During 2008 and the first half of 2009, we have significantly expanded our leasehold position in natural gas shale plays, particularly in the Haynesville Shale play in northern Louisiana and East Texas and the Eagle Ford Shale play in South Texas. We currently own leasehold interests in approximately 325,000 net acres in the Haynesville Shale play, 157,000 net acres in the Fayetteville Shale play in Arkansas, and 210,000 net acres in the Eagle Ford Shale play. The vast majority of our acreage in these plays is currently undeveloped. Typically, the leases we own require that production in paying quantities be established on units under the lease within the lease term (generally three to five years) or the lease will expire, although a significant percentage of the leases in the Haynesville Shale play are currently held by production from other producing zones. Lease expirations will be an important factor determining our capital expenditures focus over the next several years.

Production increased 65% in the first six months of 2009 which averaged 448 million cubic feet of natural gas equivalent per day (Mmcfe/d) compared to average production of 272 Mmcfe/d during the first six months of 2008. The increase in production compared to prior year is driven by our drilling successes in the Haynesville, Fayetteville and Eagle Ford Shales. Overall, we drilled 297 gross wells (75.2 net wells) of which 296 gross (74.9 net) were successful resulting in a success rate of 99%.

Our financial results depend upon many factors, but are largely driven by the volume of our oil and natural gas production and the price that we receive for that production. Our production volumes will decline as reserves are depleted unless we expend capital in successful development and exploration activities or acquire properties with existing production. The amount we realize for our production depends predominantly upon commodity prices and our related commodity price hedging activities, which are affected by changes in market demand and supply, as impacted by overall economic activity, weather, pipeline capacity constraints, inventory storage levels, basis differentials and other factors. Accordingly, finding and developing oil and natural gas reserves at economical costs is critical to our long-term success.

During the second half 2008 and continuing to date in 2009, natural gas prices have declined significantly and have remained at lower levels due to the turmoil in the global financial system and the global economic recession negatively impacting demand. In response to declining natural gas prices we have focused our 2009 capital budget on the development of non-proved locations in our Haynesville, Fayetteville and Eagle Ford Shale plays. We believe these projects also offer the potential for high internal rates of return and reserve growth. Our 2009 capital budget is $1.3 billion, exclusive of acquisitions and focuses on three primary initiatives: 1) an increase in the rig count in the Haynesville Shale by year-end 2009, providing us the ability to secure more leasehold during a year in which our production is substantially hedged; 2) infrastructure expansion in the

Haynesville Shale, based on successful drilling in new areas, gathering pipeline and facilities planned for construction in the Haynesville Shale during 2009, and 3) increased drilling activities of other operators, primarily in the Fayetteville Shale. Our future drilling plans are subject to change based upon various factors, some of which are beyond our control, including drilling results, natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals. To the extent these factors lead to reductions in our drilling plans and associated capital budgets in future periods, our financial position, cash flows and operating results could be adversely impacted.

One consequence of continued low natural gas prices is the possibility that we may be required to recognize additional non-cash impairment expense under the full cost method of accounting, which we use to account for our oil and natural gas exploration and development activities. We recorded full cost ceiling impairments before income taxes of approximately $1.7 billion and $1.0 billion at March 31, 2009 and December 31, 2008, respectively, primarily due to the decrease in the Henry Hub spot market price to $3.63 from $5.71 per million British thermal units (Mmbtu). No impairment was required at June 30, 2009 as the Henry Hub spot market price increased to $3.89. If natural gas prices continue to decline, we may be required to take additional impairment charges in the future. If the WTI posted price and Henry Hub spot market price had been 10% lower while all other factors remained constant, the Company's ceiling amount related to its net book value of oil and natural gas properties would have been reduced by approximately $300 million resulting in a ceiling test impairment of approximately $136 million, before income taxes. Changes in production rates, levels of reserves, future development costs, and other factors will determine the Company's actual ceiling test calculation and impairment analyses in future periods.

On August 4, 2009, we announced our intention to raise approximately $583 million through a public equity offering. We intend to use the net proceeds to fund potential acquisitions, a portion of our capital budget and general corporate purposes including repayment of borrowings under our senior revolving credit facility.

Capital Resources and Liquidity

Our primary sources of capital resources and liquidity are internally generated cash flows from operations, availability under our Senior Credit Agreement, and access to capital markets, to the extent available. The capital markets have been adversely impacted by the current financial crisis, concerns about overall deflation and its effect on commodity prices, the possibility of a deepening world recession that could extend for a long period into the future, and a generally higher cost of capital. Continued volatility in the capital markets could adversely impact our access to capital, which could reduce our ability to execute our development and acquisition plans, our ability to replace our reserves, and eventually, our production levels. In February 2009, we initiated a borrowing base redetermination under our Senior Credit Agreement. Our borrowing base of $950 million, along with our existing terms and pricing were reaffirmed. We continue to monitor our liquidity and the capital markets.

Our 2009 capital budget, which includes drilling, completions, seismic and facilities, is currently $1.3 billion. The allocation of capital reflects an increased emphasis on development of non-proved locations in our Haynesville, Fayetteville and Eagle Ford Shale projects as well as the continued development of our Hawk Field Services business. Our Haynesville Shale capital budget for 2009 is heavily weighted towards drilling and completion activities to fulfill our drilling obligations associated with various lease terms. We continuously evaluate our development plans in light of a variety of factors, including, but not limited to, our cash flows, capital resources and drilling success. Our weighting in this regard and the effect this may have on our development of proved undeveloped reserves can, and likely will, change.

Our future capital resources and liquidity may depend, in part, on our success in developing the leasehold interests that we acquired. Cash is required to fund capital expenditures necessary to offset inherent declines in production and proven reserves, which is typical in the capital-intensive oil and gas industry. Future success in

growing reserves and production will be highly dependent on our capital resources and our success in finding additional reserves. During 2008 and to date in 2009, we have raised $1.3 billion of debt (net of discounts and expenses) and $2.1 billion of equity capital (net of discounts and expenses). We expect to fund our future capital requirements through internally generated cash flows and borrowings under our Senior Credit Agreement, which gives us $950 million of borrowing capacity as of June 30, 2009, and through accessing the capital markets and pursuing asset monetization transactions when we consider market conditions favorable. Our ability to utilize the full amount of our borrowing capacity is influenced by a variety of factors, including semi-annual redeterminations of our borrowing base, which may also be redetermined periodically at the discretion of the banks, and covenants under our Senior Credit Agreement and our senior unsecured debt indentures limit the aggregate debt we may incur based upon the ratio of our adjusted consolidated earnings before interest, income taxes, depreciation, depletion and amortization and certain other non-cash charges (EBITDA), to our adjusted consolidated interest expense for the preceding four fiscal quarters and which may limit borrowings to a fixed percentage of our adjusted consolidated net tangible assets. Our borrowing base, EBITDA and consolidated net tangible assets are significantly influenced by, among other things, oil and natural gas prices. We strive to maintain financial flexibility while continuing our rapid growth and may access the capital markets to, among other things, maintain substantial borrowing capacity under our Senior Credit Agreement, facilitate drilling on our large undeveloped acreage position and permit us to selectively expand our acreage position and infrastructure projects. Our ability to complete future debt and equity offerings is limited by general market conditions.

Our long-term cash flows are subject to a number of variables including our level of production and commodity prices, as well as various economic conditions that have historically affected the oil and natural gas industry. If oil and natural gas prices remain at their current levels for a prolonged period of time or if natural gas prices continue to decline, our ability to fund our capital expenditures, reduce debt, meet our financial obligations and become profitable may be materially impacted.

On August 4, 2009, we announced our intent to raise approximately $583 million through a public equity offering. We intend to use the net proceeds to fund potential acquisitions, a portion of our capital budget and general corporate purposes including repayment of borrowings under our senior revolving credit facility.

Cash Flow

Our primary sources of cash for the six months ended June 30, 2009 and 2008 were from operating and financing activities. Proceeds from the sale of common stock, the issuance of new senior debt and cash received from operations were offset by repayments of our Senior Credit Agreement and cash used in investing activities to fund our drilling program and acquisition activities. Operating cash flow fluctuations were substantially driven by changes in commodity prices and changes in our production volumes. Working capital was substantially influenced by these variables. Fluctuation in cash flow may result in an increase or decrease in our future capital expenditures. Prices for oil and natural gas have historically been subject to seasonal influences typically characterized by peak demand and higher prices in the winter heating season; however, the impact of other risks and uncertainties have influenced prices throughout recent years. See "Results of Operations" below for a review of the impact of prices and volumes on revenues.

Net decrease in cash is summarized as follows:

                                                         Six Months Ended
                                                             June 30,
                                                      2009             2008
                                                          (In thousands)
     Cash flows provided by operating activities   $  326,116      $    288,589
     Cash flows used in investing activities         (787,464 )      (1,534,122 )
     Cash flows provided by financing activities      457,203         1,244,796

     Net decrease in cash                          $   (4,145 )    $       (737 )

Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2009 and 2008 were $326.1 million and $288.6 million, respectively.

Net cash provided by operating activities increased in 2009 primarily due to the 65% increase in our average daily production volumes due to our recent drilling success in the Haynesville, Fayetteville and Eagle Ford Shales partially offset by a 62% decrease in our average realized natural gas equivalent price compared to the same period in the prior year. Production for the first six months of 2009 averaged 448 Mmcfe/d compared to 272 Mmcfe/d during the same period of 2008. Our natural gas equivalent price decreased $6.44 per thousand cubic feet of natural gas equivalent (Mcfe) to $4.01 per Mcfe from $10.45 per Mcfe in the prior year. As a result of our 2009 capital budget program, we expect to continue to increase our production volumes throughout 2009. However, we are unable to predict future production levels or future commodity prices, and, therefore, we cannot provide any assurance about future levels of net cash provided by operating activities.

Investing Activities. The primary driver of cash used in investing activities is capital spending, inclusive of acquisitions and net of dispositions. Cash used in investing activities was $787.5 million and $1.5 billion for the six months ended June 30, 2009 and 2008, respectively.

During the first six months of 2009, we spent $748.1 million on acquisitions of oil and gas properties and capital expenditures. To date in 2009, we participated in the drilling of 297 gross wells (75.2 net wells). We spent an additional $145.4 million on other operating property and equipment expenditures, primarily to fund the completion of gathering systems in the Fayetteville Shale in Arkansas and the development of our gathering systems in the Haynesville Shale in Louisiana and the Eagle Ford Shale in Texas.

During the first six months of 2009, we sold a net $106.0 million of marketable securities. These marketable securities have been classified and accounted for as trading securities and were used primarily to fund a portion of our 2009 capital program.

During the first six months of 2008, we spent $1.4 billion on capital expenditures, of which approximately $1.1 billion related to acquisitions. Our acquisitions were partially funded by the remaining restricted cash that we had deposited with a qualified intermediary following the sale of our Gulf Coast properties to facilitate like-kind exchange transactions. In addition, we participated in the drilling of 328 gross wells in 2008 (121.7 net wells), six of which were dry holes. We spent an additional $31.0 million on other operating property and equipment during the first six months of 2008 as well, primarily to fund the development of gathering systems in the Fayetteville Shale in Arkansas.

On November 30, 2007, we closed the sale of our Gulf Coast properties for $825 million, before customary closing adjustments, consisting of $700 million in cash and a $125 million note from the purchaser (the Note). The Note matured five years and ninety-one days from the closing date and bore interest at 12% per annum payable in kind at the purchaser's option. The economic effective date for the sale was July 1, 2007. Proceeds from the sale were recorded as a reduction to the carrying value of our full cost pool. In conjunction with the closing of this sale, we deposited $650 million with a qualified intermediary to facilitate potential like-kind exchange transactions. At December 31, 2007, we had $269.8 million remaining for use in future acquisitions, all of which was utilized for property acquisitions during the fourth quarter of 2007 and first quarter of 2008. On April 28, 2008, the purchaser redeemed the Note for $100 million.

During the first six months of 2008, we used excess funds from our debt and equity offerings discussed below to purchase a net $490 million of marketable securities. These marketable securities were classified and accounted for as trading securities and were used primarily to fund our leasing and acquisition activities in the Haynesville Shale.

Financing Activities. Net cash flows provided by financing activities were $457.2 million and $1.2 billion for the six months ended June 30, 2009 and 2008, respectively. Cash flows provided by financing activities in the first half of 2009 were the result of the issuance of new senior notes and the sale of our common stock in an underwritten public offering.

On March 4, 2009, we sold an aggregate of 22.0 million shares of our common stock in an underwritten public offering. The net proceeds from this offering were approximately $376 million, after deducting underwriting discounts and commissions and estimated expenses.

On January 27, 2009, we completed a private placement offering to eligible purchasers of an aggregate principal amount of $600 million 10.5% senior notes due August 1, 2014. The net proceeds from the sale of the 2014 Notes were approximately $535.4 million, after deducting the initial purchasers' discounts and estimated offering expenses and commissions.

On February 1, 2008, we sold an aggregate of 20.7 million shares of our common stock in an underwritten public offering. The net proceeds from the sale were approximately $297 million, after deducting underwriting discounts and commissions and estimated expenses.

On May 13, 2008, we sold an aggregate of 25.0 million shares of our common stock in an underwritten public offering. Pursuant to the underwriting agreement, we granted the underwriters a 30-day option to purchase up to an additional 3.75 million shares of common stock at the public offering price less underwriting discounts and commissions. The underwriters exercised in full their option to purchase additional shares of common stock which closed on May 23, 2008. The net proceeds from these sales were approximately $727 million, after deducting underwriting discounts and commissions and estimated expenses.

On May 13, 2008, we issued $500 million aggregate principal amount of the 2015 Notes in a private placement under the Securities Act of 1933, as amended. The net proceeds from the sale of the 2015 Notes were approximately $490 million, after deducting the initial purchasers discounts and estimated offering expenses, including commissions.

On June 19, 2008, we issued an additional $300 million aggregate principal amount of 2015 Notes in a private placement under the Securities Act of 1933, as amended. The net proceeds from the sale of the 2015 Notes were approximately $294 million, after deducting the initial purchaser's discount and estimated offering expenses.

Capital financing and excess cash flow are used to repay borrowings under our Senior Credit Agreement to the extent available. During the first six months of 2009, we had net borrowings of $92.5 million after the application of a portion of the net proceeds from our issuance of the 2014 Notes and the sale of our common stock as discussed above to repay amounts outstanding on the Senior Credit Agreement and cash requirements of our drilling and acquisition activities. As of June 30, 2009, the Senior Credit Agreement had a $950 million borrowing base and no outstanding borrowings. During the first six months of 2008, we had net borrowings of $228.6 million.

Contractual Obligations

We have no material changes in our long-term commitments associated with our capital expenditure plans or operating agreements other than those described below. Our level of capital expenditures will vary in future periods depending on the success we experience in our acquisition, development and exploration activities, oil and natural gas price conditions and other related economic factors. Currently no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.

As of June 30, 2009, we have drilling rigs under contract with a total commitment of $355.1 million over four years. At December 31, 2008, we had drilling rigs under contract with a total commitment of $433.0 million over four years.

We have various other contractual commitments pertaining to exploration, development and production activities. We have work related commitments for, among other things, pipeline and well equipment, obtaining and processing seismic data and natural gas pipeline transportation. At June 30, 2009 and December 31, 2008, these work related commitments totaled $1.1 billion over 16 years and $507.8 million over 20 years, respectively.

Critical Accounting Policies and Estimates

Our discussion and analysis of our financial condition and results of operation are based upon the condensed consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. Preparation of these financial statements requires us to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. There have been no changes to our critical accounting policies from those described in our annual report on Form 10-K, as amended, for the year ended December 31, 2008.

Results of Operations

Quarters ended June 30, 2009 and 2008

We reported a net loss of $22.0 million for the three months ended June 30, 2009 compared to a net loss of $92.8 million for the comparable period in 2008. The decrease in our net loss of $70.8 million from the three months ended June 30, 2009 was primarily driven by $16.0 million net gain on derivative contracts for the three months ended June 30, 2009 compared to the net loss of $277.6 million on derivative contracts in the prior year. In addition our production volumes increased 71% over prior year, offset by a 69% decrease in our average realized natural gas equivalent price.

                                                         Three Months Ended
                                                              June 30,
In thousands (except per unit and per Mcfe amounts)     2009            2008           Change
Net loss available to common stockholders             $ (22,004 )    $  (92,766 )    $   70,762
Operating revenues:
Oil and natural gas                                     163,983         304,633        (140,650 )
Marketing                                                63,317              -           63,317
Expenses:
Marketing                                                60,292              -           60,292
Production:
Lease operating                                          18,704          12,903           5,801
Workover and other                                          205           1,249          (1,044 )
Taxes other than income                                  12,537          14,036          (1,499 )
Gathering, transportation and other                      22,633          10,944          11,689
General and administrative:
General and administrative                               20,185          14,133           6,052
Stock-based compensation                                  3,807           3,081             726
Depletion, depreciation and amortization:
Depletion-Full cost                                      80,656          85,597          (4,941 )
Depreciation-Other                                        3,424             786           2,638
Accretion expense                                           355             311              44
Net gain (loss) on derivative contracts                  16,006        (277,605 )       293,611
Interest expense and other                              (55,880 )       (35,154 )       (20,726 )
Income tax benefit                                       13,368          58,400         (45,032 )
Production:
Natural Gas-Mmcf (1)                                     41,485          23,413          18,072
Crude Oil-Mbbl                                              407             385              22
Natural Gas Equivalent-Mmcfe                             43,927          25,720          18,207
Average Daily Production-Mmcfe                              483             283             200
Average price per unit (2):
Gas price per Mcf (1)                                 $    3.28      $    10.99      $    (7.71 )
Oil price per Bbl                                         53.72          117.85          (64.13 )
Equivalent per Mcfe                                        3.60           11.77           (8.17 )
Average cost per Mcfe:
Production:
Lease operating                                            0.43            0.50           (0.07 )
Workover and other                                           -             0.05           (0.05 )
Taxes other than income                                    0.29            0.55           (0.26 )
Gathering, transportation and other                        0.52            0.43            0.09
General and administrative:
General and administrative                                 0.46            0.55           (0.09 )
Stock-based compensation                                   0.09            0.12           (0.03 )
Depletion                                                  1.84            3.33           (1.49 )

(1) Approximately 1% and 3% of natural gas production represents natural gas liquids (calculated with a 6:1 equivalent ratio) with an average price of $27.25 per barrel (Bbl) and $65.71 per Bbl for the three months ended June 30, 2009 and 2008, respectively.

(2) Amounts exclude the impact of cash paid/received on settled contracts as we did not elect to apply hedge accounting.

For the three months ended June 30, 2009, oil and natural gas revenues decreased . . .