The following discussion of operations for the three ended March 31, 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 oil and natural gas 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, 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. We have aggressively expanded our leasehold position in resource-style natural gas plays within our core operating areas, particularly in the Haynesville Shale play in northern Louisiana and East Texas. We currently own leasehold interests in approximately 300,000 net acres in the Haynesville Shale play. We also own leasehold interests covering approximately 157,000 net acres in the Fayetteville Shale in Arkansas, and, during 2008, we announced our discovery of the Eagle Ford Shale play in South Texas, where we currently own leasehold interests in approximately 160,000 net acres. 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 for the first quarter of 2009 averaged 412 million cubic feet of natural gas equivalent per day (Mmcfe/d), a 58% increase over first quarter 2008 production of 261 Mmcfe/d. The increase in production compared to prior year is primarily due to our recent drilling successes in the Haynesville, Fayetteville and Eagle Ford Shales. In the Haynesville Shale, we utilized eight horizontal rigs on average during the first quarter, not including spudder rigs. A total of 15 operated wells were drilled, of which 11 were on production at the end of the quarter. Additionally, five operated wells drilled in late 2008 were put on production, bringing the total number of Haynesville Shale wells completed to
28. The average initial production rate for wells completed during the first quarter of 2009 was 17.1 Mmcfe/d. Initial production rates ranged from 3.3 Mmcfe/d to 24.8 Mmfe/d. In the Eagle Ford Shale, throughout the first quarter, we operated one horizontal rig in the play and recently added a second rig. Three wells were drilled and two were completed during the quarter with average initial production rates of 6.1 Mmcfe/d and 9.3 Mmcfe/d. In the Fayetteville Shale, we averaged two operated horizontal rigs during the quarter and a total of 14 operated wells and 95 non-operated wells were drilled during the quarter. Overall, we drilled 165 gross wells (40.9 net wells) of which 164 gross (40.7 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, 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, and secondarily upon our commodity price hedging activities. 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, oil and natural gas prices declined significantly due to the turmoil in the global financial system and the global economic recession. In response to declining oil and 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 offer the potential for the highest internal rates of return and reserve growth. We have increased our 2009 capital budget from $1.0 billion to $1.3 billion, exclusive of acquisitions. The revised budget will focus on three primary initiatives: 1) increased drilling activities of other operators, primarily in the Fayetteville Shale; 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 are now approximately 150 miles; and 3) an increase in the rig count in the Haynesville Shale to 16 by year-end 2009, providing us the ability to secure more leasehold during a year in which our production is substantially hedged. Our future drilling plans are subject to change based upon various factors, some of which are beyond our control, including drilling results, oil and 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.

Another consequence we face as a result of declining oil and 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). If natural gas prices continue to decline, we may be required to take additional impairment charges in the future.

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 the 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 undrawn borrowing base of $950 million, along with our existing terms and pricing were reaffirmed. We will 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 and is allocated to projects with the highest internal rates of return and highest potential for reserve growth. The allocation of capital reflects an increased emphasis on development of non-proved locations in our successful Haynesville, Fayetteville and Eagle Ford Shale projects. We continue to monitor the oil and natural gas markets and may adjust our capital program should circumstance warrant it.

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, borrowings under our Senior Credit Agreement, which gives us $950 million of borrowing capacity as of today. Our ability to utilize the full amount of our current

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 that limit the 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 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 equity offerings is limited by the availability of authorized common stock under our certificate of incorporation and 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.

Cash Flow

Our primary sources of cash for the three months ended March 31, 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) increase in cash is summarized as follows:

                                                        Three Months Ended
                                                             March 31,
                                                        2009           2008
                                                          (In thousands)
       Cash flows provided by operating activities   $  156,358     $   61,185
       Cash flows used in investing activities         (620,412 )     (323,312 )
       Cash flows provided by financing activities      458,865        267,514

       Net (decrease) increase in cash               $   (5,189 )   $    5,387

Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2009 and 2008 were $156.4 million and $61.2 million, respectively.

Net cash provided by operating activities increased in 2009 primarily due to the 58% increase in our average daily production volumes due to our recent drilling success in the Haynesville, Fayetteville and Eagle Ford Shales partially offset by the 50% decrease in our average realized natural gas equivalent price compared to the same period in the prior year. Production for the first quarter 2009 averaged 412 Mmcfe/d compared to 261

Mmcfe/d during the first quarter of 2008. Our natural gas equivalent price decreased $4.54 per thousand cubic feet of natural gas equivalent (Mcfe) to $4.49 per Mcfe from $9.03 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 $620.4 million and $323.3 million for the three months ended March 31, 2009 and 2008, respectively.

During the first three months of 2009, we spent $390.7 million on acquisitions of oil and gas properties and capital expenditures. In 2009, we participated in the drilling of 165 gross wells (40.9 net wells). We spent an additional $69.7 million on other property and equipment expenditures, primarily to fund the completion of gathering systems in the Fayetteville Shale in Arkansas and the beginning stages of the development of our gathering systems in the Haynesville Shale in Louisiana.

During the first three months of 2009, we used a portion of the funds from our debt and equity offerings discussed below to purchase a net $160.0 million of marketable securities. These marketable securities have been classified and accounted for as trading securities and will be used primarily to fund a portion of our 2009 capital program.

During the first three months of 2008, we spent $578.7 million on acquisitions of oil and gas properties and capital expenditures. We spent $428.3 million primarily to acquire additional interests in the Fayetteville Shale in Arkansas, in both the Elm Grove and Terryville fields in Louisiana and in the Haynesville Shale in Louisiana, which was partially funded by the remaining restricted cash that we had deposited with a qualified intermediary to facilitate like-kind exchange transactions following the sale of Gulf Coast properties. Additionally, we spent $150.4 million on capital expenditures in conjunction with our drilling program. We spent an additional $14.4 million on other property and equipment expenditures during the first three 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.

Financing Activities. Net cash flows provided by financing activities were $458.9 million and $267.5 million for the three months ended March 31, 2009 and 2008, respectively. Cash flows provided by financing activities in the first quarter 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.

Capital financing and excess cash flow are used to repay borrowings under our Senior Credit Agreement to the extent available. During the first three months of 2009, we had net borrowings of $95.4 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 March 31, 2009, the Senior Credit Agreement had a $950 million borrowing base and no outstanding borrowings. During the first three months of 2008, we had net repayments of $35 million under our Senior Credit Agreement primarily funded by the sale of common stock discussed above, offset by the cash requirements of our drilling program and our acquisition activities in 2008.

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.

At December 31, 2008, we had drilling rigs under contract for a total commitment of $433.0 million over four years. As of March 31, 2009, we have drilling rigs under contract for a total commitment of $380.9 million over the next 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 transportation. At March 31, 2009 and December 31, 2008, these work related commitments totaled $1.1 billion over the next 16 years and $507.8 million over the next 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 of America. 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 March 31, 2009 and 2008

We reported a net loss of $999.8 million for the three months ended March 31, 2009 compared to a net loss of $55.6 million for the comparable period in 2008. The increase in our net loss of $944.1 million from the three months ended March 31, 2009 was primarily driven by our full cost ceiling impairment of $1.7 billion before taxes, partially offset by our net gain on derivative contracts of $181.9 million compared to a net loss on derivative contracts of $142.7 million in the prior year.

                                                          Three Months Ended
                                                              March 31,
In thousands (except per unit and per Mcfe amounts)      2009            2008          Change
Net loss available to common stockholders             $  (999,753 )   $  (55,612 )   $  (944,141 )
Operating revenues:
Oil and natural gas                                       173,762        214,938         (41,176 )
Marketing                                                  89,693             -           89,693
Expenses:
Marketing                                                  84,844             -           84,844
Production:
Lease operating                                            16,411         12,394           4,017
Workover and other                                            723            537             186
Taxes other than income                                    12,180         10,964           1,216
Gathering, transportation and other                        20,494          9,523          10,971
General and administrative:
General and administrative                                 16,829         13,556           3,273
Stock-based compensation                                    2,810          2,598             212
Depletion, depreciation and amortization:
Depletion-Full cost                                       111,092         82,073          29,019
Depreciation-Other                                          2,819            771           2,048
Accretion expense                                             345            283              62
Full cost ceiling impairment                            1,732,486             -        1,732,486
Net gain (loss) on derivative contracts                   181,922       (142,741 )       324,663
Interest expense and other                                (56,068 )      (27,537 )       (28,531 )
Income tax benefit                                        611,971         32,427         579,544
Production:
Natural gas-Mmcf (1)                                       34,591         21,523          13,068
Crude oil-MBbl                                                414            365              49
Natural gas equivalent-Mmcfe                               37,075         23,713          13,362
Daily production-Mmcfe                                        412            261             151
Average price per unit (2):
Natural gas price-Mcf (1)                             $      4.36     $     8.34     $     (3.98 )
Crude oil price-Bbl                                         38.10          94.86          (56.76 )
Equivalent-Mcfe                                              4.49           9.03           (4.54 )
Average cost per Mcfe:
Production:
Lease operating                                              0.44           0.52           (0.08 )
Workover and other                                           0.02           0.02              -
Taxes other than income                                      0.33           0.46           (0.13 )
Gathering, transportation and other                          0.55           0.40            0.15
General and administrative:
General and administrative                                   0.45           0.57           (0.12 )
Stock-based compensation                                     0.08           0.11           (0.03 )
Depletion                                                    3.00           3.46           (0.46 )

(1) Approximately 2% and 3% of natural gas production represents natural gas liquids (calculated with a 6:1 equivalent ratio) with an average price of $23.23 per Bbl and $61.55 per Bbl for the three months ended March 31, 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 March 31, 2009, oil and natural gas revenues decreased $41.2 million from the same period in 2008, to $173.8 million. The decrease was primarily due to the decrease of $4.54 per Mcfe in our realized average price to $4.49 per Mcfe from $9.03 per Mcfe in the prior year. This decrease per Mcfe led to a decrease in oil and natural gas revenues of $168 million. The effect of the decrease in price was partially offset by an increase in production of 13,362 Mmcfe due to our recent drilling successes in resource-style plays in Louisiana, Arkansas and Texas. Increased production led to an approximate $127 million increase in revenues for the three months ended March 31, 2009.

We had marketing revenues of $89.7 million and marketing expenses of $84.8 million for the three months ended March 31, 2009, resulting in a net margin of $4.9 million. During the fourth quarter of 2008, we began purchasing and selling third party natural gas produced from wells we operate. We report the revenues and expenses related to these marketing activities on a gross basis as part of our operating revenues and operating expenses. Marketing revenues are recorded at the time natural gas is physically delivered to third parties at a fixed or index price. Marketing expenses attributable to gas purchases are recorded as we take physical title to the natural gas and transport the purchased volumes to the point of sale.

Lease operating expenses increased $4.0 million for the three months ended March 31, 2009. The increase was primarily due to the increase in production volumes as a result of our recent drilling successes in our resource-style plays in Louisiana, Arkansas and Texas. On a per unit basis, lease operating expenses decreased from $0.52 per Mcfe in 2008 to $0.44 per Mcfe in 2009. This decrease on a per unit basis is primarily due to the increase in production in our resource-style plays which have lower lease operating costs.

Taxes other than income increased $1.2 million for the three months ended . . .