The following discussion of operations for the three and nine months ended September 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. Beginning in 2008 and continuing in 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. 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.

Average daily production increased 64% in the first nine months of 2009 which averaged 469 million cubic feet of natural gas equivalent per day (Mmcfe/d) compared to average production of 286 Mmcfe/d during the first nine 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 or participated in the drilling of 467 gross wells (123.3 net wells) of which 466 gross (123.1 net) were successful resulting in a success rate of 99.8%.

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.

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. We recently increased our capital budget for drilling, completions, seismic and workovers $100 million to $1.1 billion from $1.0 billion of our total $1.3 billion capital budget for 2009, exclusive of acquisitions. We plan to capitalize on additional drilling and seismic opportunities in the Haynesville and Eagle Ford Shales during the fourth quarter of 2009 with our increased budget. We expect to spend approximately $1.45 billion in 2010 on drilling and completion activities and an additional $250 million on infrastructure expansion. We also expect to spend an additional $100 million to $300 million on ongoing leasing activities. Our future drilling plans and infrastructure 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 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. At September 30, 2009, our net book value of oil and gas properties exceeded our ceiling amount by approximately $880 million before tax, $546 million after tax based on the September 30, 2009 WTI posted price of $70.61 per barrel and the Henry Hub spot market price of $3.30 per Mmbtu. However, subsequent to September 30, 2009, the market price for Henry Hub gas and WTI oil increased significantly. As a consequence, prior to October 28, 2009, we elected to use prices on October 28, 2009, which were a WTI posted price of $77.20 per barrel and a Henry Hub spot market price of $4.51 per Mmbtu, adjusted for certain items as previously discussed. Utilizing these prices, our net book value of oil and natural gas properties at September 30, 2009, did not exceed the ceiling amount. As a result of the increase in the ceiling amount using the subsequent prices, we did not record a write-down of our oil and natural gas property costs. If natural gas prices decline, we may be required to take additional impairment charges in the future. If the September 30, 2009 WTI posted price and Henry Hub spot market price had been 10% lower while all other factors remained constant, our ceiling amount related to its net book value of oil and natural gas properties would have been reduced by approximately $206 million resulting in an additional ceiling test impairment of approximately $332 million, before income taxes had we not elected to use subsequent prices as of October 28, 2009. Changes in production rates, levels of reserves, future development costs, and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

On October 14, 2009, we entered into the Fourth Amended and Restated Senior Revolving Credit Agreement (the Fourth Amendment), which amends and restates our Third Amended and Restated Senior Revolving Credit Agreement dated September 10, 2008. The Fourth Amendment is a $2.0 billion facility with an initial borrowing base of $1.5 billion, $1.2 billion of which relates to our oil and natural gas properties and up to $300 million (currently limited as described below) of which relates to our midstream assets. The portion of the borrowing base which relates to our oil and natural gas properties will be redetermined on a semi-annual basis (with us and the Lenders each having the right to one annual interim unscheduled redetermination) and adjusted based on our oil and natural gas properties, reserves, other indebtedness and other relevant factors. The component of the borrowing base related to our midstream assets is limited to the lesser of $300 million or 3.5 times midstream EBITDA, and is determined quarterly. The initial available borrowing base aggregates $1.38 billion as the midstream component is currently $182 million. Amounts outstanding under the Fourth Amendment will bear interest at specified margins over LIBOR of 2.25% to 3.25% for Eurodollar loans or at specified margins over ABR of 0.75% to 1.75% for ABR loans. Such margins will fluctuate based on the utilization of the facility. Borrowings under the Fourth Amendment will be secured by first priority liens on substantially all of our assets, including pursuant to the terms of the Fourth Amended and Restated Guarantee and Collateral Agreement, all of the assets of, and equity interests in, our subsidiaries. Amounts drawn down on the facility will mature on July 1, 2013.

On October 30, 2009, we closed our previously announced sale of our Permian Basin properties to a privately-owned company for $376 million in cash, before customary closing adjustments, $37.6 million of which we received as a deposit during the third quarter. The effective date of the sale was July 1, 2009. Proceeds from the sale will be recorded as a reduction to the carrying value of our full cost pool. Upon closing of this sale, the oil and gas properties portion of the borrowing base under the Fourth Amendment was reduced by $200 million to $1 billion, resulting in a new aggregate borrowing base of $1.18 billion, including our midstream assets allocation. In conjunction with the closing of this sale, we deposited the remaining proceeds with a qualified intermediary to facilitate potential like-kind exchange transactions.

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. We continue to monitor our liquidity and the capital markets. 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 natural 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 $2.7 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 September 30, 2009 (updated to $1.18 billion after entering into the Fourth Amendment to the Credit Agreement and closing on the sale of our Permian Basin properties), pursuing asset monetization transactions when we consider market conditions favorable, and accessing the capital markets, if necessary. 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. Our senior indenture covenants 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.

Cash Flow

Our primary sources of cash for the nine months ended September 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) increase in cash is summarized as follows:

                                                        Nine Months Ended
                                                          September 30,
                                                      2009              2008
                                                          (In thousands)
    Cash flows provided by operating activities   $    474,750      $    525,784
    Cash flows used in investing activities         (1,483,517 )      (2,497,027 )
    Cash flows provided by financing activities      1,003,576         1,973,310

    Net (decrease) increase in cash               $     (5,191 )    $      2,067

Operating Activities. Net cash provided by operating activities for the nine months ended September 30, 2009 and 2008 were $474.8 million and $525.8 million, respectively.

Net cash provided by operating activities decreased in 2009 primarily due to the 63% decrease in our average realized natural gas equivalent price compared to the same period in the prior year partially offset by a 64% increase in our average daily production volumes due to our recent drilling success in the Haynesville, Fayetteville and Eagle Ford Shales. Our natural gas equivalent price decreased $6.62 per thousand cubic feet of natural gas equivalent (Mcfe) to $3.83 per Mcfe from $10.45 per Mcfe in the prior year. Production for the first nine months of 2009 averaged 469 Mmcfe/d compared to 286 Mmcfe/d during the same period of 2008. As a result of our 2009 capital budget program, we expect to continue to increase our production volumes throughout 2009 and 2010. However, we are unable to predict future production levels or future commodity prices with certainty, 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 $1.5 billion and $2.5 billion for the nine months ended September 30, 2009 and 2008, respectively.

During the first nine months of 2009, we spent $1.2 billion on oil and natural gas capital expenditures. To date in 2009, we participated in the drilling of 467 gross wells (123.3 net wells). We spent an additional $225.3 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 nine months of 2009, we used excess funds to purchase a net $27.0 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.

On July 31, 2009, we purchased all outstanding membership interests in Kaiser Trading, LLC (Kaiser) for approximately $105 million. Kaiser's only assets were transportation-related contracts including a firm transportation contract, interruptible gas transportation service agreement, parking and lending services agreement, and a pooling services agreement. The initial firm transportation contract runs-through 2013 and at no additional cost, we have the contractual right to extend firm supply through 2019. The purchase price has been allocated to transportation contract which will be amortized on a straight line basis over the life of the extended agreement.

On September 18, 2009, we entered into a definitive agreement to sell our Permian Basin properties to a privately-owned company for $376 million in cash, before customary closing adjustments. In conjunction with

the signing of the agreement, we received a $37.6 million deposit. The deal closed on October 30, 2009. The effective date of the sale was July 1, 2009. Proceeds from the sale will be recorded as a reduction to the carrying value of our full cost pool. In conjunction with the closing of this sale, we deposited the remaining proceeds with a qualified intermediary to facilitate potential like-kind exchange transactions.

During the first nine months of 2008, we spent $2.5 billion on oil and natural gas capital expenditures. 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. Our program to acquire additional interests and acreage in our key areas, including the Fayetteville Shale in Arkansas; Elm Grove, and Terryville fields in Louisiana, the Haynesville Shale in Louisiana and the Eagle Ford Shale in Texas is ongoing on a selective basis. In addition, we participated in the drilling of 523 gross wells in 2008 (194.6 net wells). We spent an additional $75.5 million on other operating property and equipment during the first nine 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 first quarter of 2008. On April 28, 2008, the purchaser redeemed the Note for $100 million.

During the first nine months of 2008, we used excess funds from our debt and equity offerings discussed below to purchase a net $252.7 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 $1.0 billion and $2.0 billion for the nine months ended September 30, 2009 and 2008, respectively. Cash flows provided by financing activities in the first nine months of 2009 were the result of the issuance of new senior notes and the sale of our common stock.

On August 11, 2009, we sold an aggregate of 25.0 million shares of our common stock in an underwritten public offering. The net proceeds from the sale were approximately $550 million, after deducting underwriting discounts and commissions and expenses.

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 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 offering expenses and commissions.

On August 15, 2008, we sold an aggregate of 28.8 million shares of our common stock in an underwritten public offering. The net proceeds from the sale were approximately $734 million, after deducting underwriting discounts and commissions and expenses.

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 offering 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 offering expenses, including commissions.

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 expenses.

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 expenses.

Capital financing and excess cash flow from operations are used to repay borrowings under our Senior Credit Agreement to the extent available. During the first nine months of 2009, we had net borrowings of $88.2 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. During the first nine months of 2008, we had net borrowings of $227.7 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. We have no sources of liquidity or financing are provided by off-balance sheet arrangements or transactions with unconsolidated, limited-purpose entities.

As of September 30, 2009, we had drilling rigs under contract with a total commitment of $316.0 million over approximately 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 September 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 September 30, 2009 and 2008

We reported a net loss of $40.2 million for the three months ended September 30, 2009 compared to net income of $305.4 million for the comparable period in 2008, resulting in a net change of $345.6 million. This change was primarily attributable to a $1.6 million net loss on derivative contracts for the three months ended September 30, 2009 versus a net gain of $388.2 million for the 2008 period. Also contributing to the change were lower revenues partially offset by lower income tax expense.

                                                         Three Months Ended
                                                            September 30,
In thousands (except per unit and per Mcfe amounts)     2009            2008           Change
Net (loss) income available to common stockholders    $ (40,177 )    $  305,465      $ (345,642 )
. . .