The following updates information as to Southwestern Energy Company's financial condition provided in our 2008 Annual Report on Form 10-K and analyzes the changes in the results of operations between the three- and nine-month periods ended September 30, 2009 and 2008. For definitions of commonly used natural gas and oil terms used in this Form 10-Q, please refer to the "Glossary of Certain Industry Terms" provided in our 2008 Annual Report on Form 10-K.

The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results could differ materially from those anticipated in our forward-looking statements for many reasons, including the risks described in the "Cautionary Statement About Forward-Looking Statements" in the forepart of this Form 10-Q, in Item 1A, "Risk Factors" in Part I and elsewhere in our 2008 Annual Report on Form 10-K, and Item 1A, "Risk Factors" in Part II in this Form 10-Q and any other Form 10-Q filed during the fiscal year. You should read the following discussion with our unaudited condensed consolidated financial statements and the related notes included in this Form 10-Q.

Southwestern Energy Company is an independent energy company primarily engaged in natural gas and crude oil exploration, development and production ("E&P") within the United States. We are also focused on creating and capturing additional value through our natural gas gathering and marketing businesses ("Midstream Services"). We have historically operated principally in three segments: E&P, Midstream Services and Natural Gas Distribution. On July 1, 2008, we closed the sale of our utility subsidiary, Arkansas Western Gas Company ("AWG") and, as a result, no longer have any natural gas distribution operations. The operating results and cash flows from AWG through June 30, 2008 are included in the unaudited condensed consolidated statements of operations and statements of cash flows, as applicable, and are not presented as "discontinued operations." We refer you to Note 4 to the unaudited condensed consolidated financial statements included in this Form 10-Q for additional information.

We derive the vast majority of our operating income and cash flow from the natural gas production of our E&P business and expect this to continue in the future. We expect that growth in our operating income and revenues will primarily depend on natural gas prices and our ability to increase our natural gas production. Our ability to increase our natural gas production is dependent upon our ability to economically find and produce natural gas, our ability to control costs and our ability to market natural gas on economically attractive terms to our customers. In recent years, there has been significant price volatility in natural gas and crude oil prices due to a variety of factors we cannot control or predict. These factors, which include weather conditions, political and economic events, and competition from other energy sources, impact supply and demand for natural gas, which in turn determines the sale prices for our production. In addition, the prices we realize for our production are affected by our hedging activities as well as locational differences in market prices. We are subject to credit risk relating to the risk of loss as a result of non-performance by counterparties in our hedging activities. The counterparties are primarily major investment and commercial banks which management believes present minimal credit risks. The credit quality of each counterparty and the level of financial exposure we have to each counterparty are closely monitored to limit our credit risk exposure. We have not incurred any counterparty losses related to non-performance and do not anticipate any losses given the information we have currently. However, given the current volatility in the financial markets, we cannot be certain that we will not experience such losses in the future.

As a result of the ongoing development of our Fayetteville Shale play and our improving well performance, we have experienced over 50% growth in our production volumes in the first nine months of 2009 as compared with the prior year. However, the increase in our revenues resulting from our production growth was more than offset by significantly lower realized prices for natural gas over the same period. We expect our production growth over 2008, as discussed in more detail in our guidance below, to continue for the remainder of the year. We rely in part upon the Fayetteville and Greenville Laterals built by Texas Gas Transmission, LLC ("Texas Gas"), a subsidiary of Boardwalk Pipeline Partners, LP, to service our increased production from the Fayetteville Shale play. We curtailed a portion of our natural gas production during the third quarter of 2009 as a result of inspections, repairs and maintenance relating to the remediation of pipe anomalies on the Fayetteville and Greenville Lateral. The remediation of the pipe anomalies by Texas Gas was pursuant to an agreement with Pipeline and Hazardous Materials Safety Administration ("PHMSA") entered during the second quarter 2009, which defined the testing protocol and remediation efforts that Texas Gas would need to complete in order to return to normal operating pressures, and for the Fayetteville Lateral, to operate at

higher than normal operating pressures. The testing protocol and remediation efforts include replacement of certain pipe joints, performing investigative digs to physically inspect the pipe sections and conducting metallurgical testing and analysis on a variety of pipe samples. On October 8, 2009, Texas Gas announced it received authorization from the PHMSA to operate the Fayetteville and Greenville Laterals at standard operating pressures with a capacity of 805,000 MMBtu per day. Texas Gas is continuing to perform the testing protocol required by PHMSA and, once that testing has been completed and the results known, expects to request from PHMSA the authority to operate the Fayetteville Lateral at higher than normal operating pressures under a special permit. In addition, Texas Gas plans to add compression in 2010 that will increase peak-day delivery capacities to approximately 1.0 Bcf per day on the Greenville Lateral, and assuming that the authority is received to operate the Fayetteville Lateral at higher than normal operating pressures, increase peak-day delivery capacities to approximately 1.3 Bcf per day on the Fayetteville Lateral. The compression for the Fayetteville and Greenville Laterals has been approved by FERC. PHMSA retains discretion as to whether to grant, or to maintain in force, authority to operate a pipeline at higher than normal operating pressures. We cannot predict when or if the Fayetteville Lateral will be able to operate at higher capacities. In addition, PHMSA mandated repairs in conjunction with obtaining the special operating permit or any other substantial delay in obtaining the special operating permit from PHMSA could result in future curtailments of our capacity.

Three Months Ended September 30, 2009 Compared with Three Months Ended September 30, 2008

Our natural gas and oil production increased to 73.2 Bcfe for the three months ended September 30, 2009, up 38% from the three months ended September 30, 2008.
The 20.3 Bcfe increase in 2009 production was primarily due to a 21.6 Bcf increase in net production from our Fayetteville Shale play as a result of our ongoing development program. The average price realized for our gas production, including the effects of hedges, decreased approximately 41% to $5.06 per Mcf for the three months ended September 30, 2009, as compared to the same period in 2008.

We reported net income attributable to Southwestern Energy of $118.3 million for the three months ended September 30, 2009, or $0.34 per diluted share, down from $218.2 million, or $0.63 per diluted share, for the comparable period in 2008. Our operating results for the three months ended September 30, 2008 include a $57.3 million pre-tax gain related to the sale of AWG in the third quarter of 2008.

Our E&P segment reported operating income of $172.0 million for the three months ended September 30, 2009, down $108.6 million from the comparable period of 2008, primarily due to the effects of significantly lower gas and oil prices which decreased revenues by $257.6 million and an increase in operating costs and expenses of $21.4 million relating to our increased gas production which more than offset the higher revenues of $170.4 million realized from increased gas production volumes. Operating income for our Midstream Services segment was $25.1 million for the three months ended September 30, 2009, up from $18.3 million for the three months ended September 30, 2008, due to an increase of $15.1 million in gathering revenues and an increase of $0.9 million in the margin generated from our natural gas marketing activities, which were partially offset by a $9.2 million increase in operating costs and expenses, exclusive of gas purchase costs.

We had capital investments of $408.8 million for the three months ended September 30, 2009, of which $333.9 million was invested in our E&P segment compared to $471.6 million for the same period of 2008, of which $415.7 million was invested in our E&P segment.

Nine Months Ended September 30, 2009 Compared with Nine Months Ended September 30, 2008

For the nine months ended September 30, 2009, our gas and oil production increased to 211.4 Bcfe, up 54% compared to the same period in 2008. The 74.4 Bcfe increase in 2009 production was due to a 79.2 Bcf increase in net production from our Fayetteville Shale play, partially offset by decreases in net production resulting from the sale of all of our producing properties in the Permian Basin and Gulf Coast. The average price realized for our gas production, including the effects of hedges, decreased approximately 35% to $5.31 per Mcf for the nine months ended September 30, 2009, as compared to the same period last year.

We reported a net loss attributable to Southwestern Energy of $193.5 million for the nine months ended September 30, 2009, or $0.56 per diluted share, down from net income attributable to Southwestern Energy of $463.7 million, or $1.34 per diluted share, for the comparable period in 2008. The loss includes the recognition of a $907.8 million, or $558.3 million net of taxes, non-cash ceiling test impairment of our natural gas and oil properties recorded during the three months ended March 31, 2009. The ceiling test impairment was recognized as a result of a significant decline in

natural gas prices. Our operating results for the nine months ended September 30, 2008 include a $57.3 million pre-tax gain related to the sale of AWG in the third quarter of 2008.

Our E&P segment reported an operating loss of $381.4 million for the nine months ended September 30, 2009, down $1,042.8 million from the comparable period of 2008, due to the $907.8 million non-cash ceiling test impairment of our natural gas and oil properties, decreased prices realized from the sale of our production, and an increase in operating costs and expenses of $108.9 million relating to our increased gas production all of which more than offset the higher revenues of $593.5 million realized from increased gas production volumes. Operating income for our Midstream Services segment was $80.3 million for the nine months ended September 30, 2009, up from $43.4 million for the nine months ended September 30, 2008, due to a $59.7 million increase in gathering revenues and a $4.6 million increase in the margin generated from our natural gas marketing activities, which were partially offset by a $27.5 million increase in operating costs and expenses, exclusive of gas purchase costs. Our Natural Gas Distribution segment, which was sold as of July 1, 2008, had operating income of $10.7 million as of the sale date that is included in our results for the nine months ended September 30, 2008.

We had capital investments of $1,368.2 million for the nine months ended September 30, 2009, of which $1,186.4 million was invested in our E&P segment compared to $1,297.0 million for the same period of 2008, of which $1,155.0 million was invested in our E&P segment.

The following discussion of our results of operations for our segments is presented before intersegment eliminations. We evaluate our segments as if they were stand alone operations and accordingly discuss their results prior to any intersegment eliminations. Interest expense, interest income, income tax expense, pension expense and stock-based compensation are discussed on a consolidated basis.

Exploration and Production
                                            For the three months                 For the nine months
                                             ended September 30,                 ended September 30,
                                           2009             2008                2009                2008

Revenues (in thousands)                $    371,034      $    458,173         $   1,121,800    $   1,147,915
Impairment of natural gas and oil
properties (in thousands)               $         ?       $         ?          $    907,812      $         ?
Operating costs and expenses (in
thousands)                             $    198,996      $    177,566          $    595,410     $    486,512
Operating income (loss) (in thousands) $    172,038      $    280,607          $   (381,422)    $    661,403

Gas production (MMcf)                        72,982            52,375               210,791          134,892
Oil production (MBbls)                           29                76                    95              345
Total production (MMcfe)                     73,150            52,832               211,358          136,964

Average gas price per Mcf, including
hedges                                 $       5.06      $       8.56          $       5.31     $       8.19
Average gas price per Mcf, excluding
hedges                                 $       2.85      $       8.82          $       3.16     $       8.83
Average oil price per Bbl              $      64.20      $     125.33          $      49.47     $     112.37

Average unit costs per Mcfe:
Lease operating expenses               $       0.76      $       0.96          $       0.76     $       0.90
General & administrative expenses      $       0.38      $       0.33          $       0.34     $       0.38
Taxes, other than income taxes         $       0.10      $       0.15          $       0.10     $       0.15
Full cost pool amortization            $       1.43      $       1.86          $       1.56     $       2.03

Revenues

Revenues for our E&P segment were down $87.1 million, or 19%, for the three months ended September 30, 2009 compared to the same period in 2008. Lower natural gas and oil prices in the third quarter of 2009 decreased revenues by $257.6 million, which were partially offset by a $170.4 million increase in revenue attributable to increased production volumes. E&P revenues were down $26.1 million, or 2%, for the nine months ended September 30, 2009 compared to the nine months ended September 30, 2008. This decrease was due to the negative $614.2 million impact of lower realized natural gas and oil prices, a $4.3 million non-cash impairment of our natural gas inventory and $1.1 million from other declines in our revenue which were partially offset by a $593.5 million increase attributable to increased production volumes. We expect our production volumes to continue to increase due to the development of our

Fayetteville Shale play in Arkansas. Natural gas and oil prices are difficult to predict and subject to wide price fluctuations. As of October 27, 2009, we had hedged 33.0 Bcf of our remaining 2009 gas production, 50.0 Bcf of 2010 gas production and 30.0 Bcf of 2011 gas production to limit our exposure to price fluctuations. We refer you to Note 6 to the unaudited condensed consolidated financial statements included in this Form 10-Q and to the discussion of "Commodity Prices" provided below for additional information.

Production

Natural gas and oil production for the three months ended September 30, 2009 was up approximately 38%, from the comparable period in 2008, to 73.2 Bcfe, due to a
21.6 Bcf increase in net production from our Fayetteville Shale play as a result of our ongoing development program. Gas production represented nearly 100% of our total gas and oil equivalent production for the three months ended September 30, 2009 and was up approximately 39% to 73.0 Bcf compared to the same period in 2008. Net production from the Fayetteville Shale was 58.8 Bcf for the three months ended September 30, 2009 compared to 37.2 Bcf for the same period in 2008. Natural gas and oil production for the nine months ended September 30, 2009 was up approximately 54%, from the comparable period in 2008, to 211.4 Bcfe, due to a 79.2 Bcf increase in net production from our Fayetteville Shale play as a result of our ongoing development program, which was partially offset by a decrease of 3.1 Bcfe in net production resulting from the sale of all of our producing properties in the Permian Basin and Gulf Coast. Gas production represented nearly 100% of our total gas and oil equivalent production for the nine months ended September 30, 2009 and was up approximately 56% to 210.8 Bcf compared to the same period in 2008. Net production from the Fayetteville Shale was 169.6 Bcf for the nine months ended September 30, 2009 compared to 90.4 Bcf for the same period in 2008.

In the second quarter of 2008, we completed the sale of 55,631 net acres, or approximately 6% of our December 31, 2007 total net acres in the Fayetteville Shale play, for $518.3 million. Production from the acreage sold was approximately 10.5 MMcf per day at the time of the sale. Additionally, we sold our Gulf Coast and Permian Basin properties in the second and third quarters of 2008.

We rely in part upon the Fayetteville and Greenville Laterals built by Texas Gas, a subsidiary of Boardwalk Pipeline Partners, LP, to service our increased production from the Fayetteville Shale play. We curtailed a portion of our natural gas production during the third quarter of 2009 as a result of inspections, repairs and maintenance relating to the remediation of pipe anomalies on the Fayetteville and Greenville Lateral. The remediation of the pipe anomalies by Texas Gas was pursuant to an agreement with PHMSA entered during the second quarter 2009, which defined the testing protocol and remediation efforts that Texas Gas would need to complete in order to return to normal operating pressures, and for the Fayetteville Lateral, to operate at higher than normal operating pressures. The testing protocol and remediation efforts include replacement of certain pipe joints, performing investigative digs to physically inspect the pipe sections and conducting metallurgical testing and analysis on a variety of pipe samples. On October 8, 2009, Texas Gas announced it received authorization from the PHMSA to operate the Fayetteville and Greenville Laterals at standard operating pressures with a capacity of 805,000 MMBtu per day. Texas Gas is continuing to perform the testing protocol required by PHMSA and, once that testing has been completed and the results known, expects to request from PHMSA the authority to operate the Fayetteville Lateral at higher than normal operating pressures under a special permit. In addition, Texas Gas plans to add compression in 2010 that will increase peak-day delivery capacities to approximately 1.0 Bcf per day on the Greenville Lateral, and assuming that the authority is received to operate the Fayetteville Lateral at higher than normal operating pressures, increase peak-day delivery capacities to approximately 1.3 Bcf per day on the Fayetteville Lateral. The compression for the Fayetteville and Greenville Laterals has been approved by FERC. PHMSA retains discretion as to whether to grant, or to maintain in force, authority to operate a pipeline at higher than normal operating pressures. We cannot predict when or if the Fayetteville Lateral will be able to operate at higher capacities. In addition, PHMSA mandated repairs in conjunction with obtaining the special operating permit or any other substantial delay in obtaining the special operating permit from PHMSA could result in future curtailments of our capacity.

We have increased our natural gas and oil production guidance for the fourth quarter of 2009 to 86 to 89 Bcfe, up from 74 to 82 Bcfe. Our guidance for 2009 natural gas and oil production is now 297 to 300 Bcfe, which is an increase of approximately 53% over our actual natural gas and oil production for 2008 of
194.6 Bcfe. Of this total for 2009, approximately 243 to 245 Bcf is expected to come from the Fayetteville Shale play.

Commodity Prices

The average price realized for our gas production, including the effects of hedges, decreased approximately 41% to $5.06 per Mcf for the three months ended September 30, 2009, and decreased 35% to $5.31 per Mcf for the nine months ended September 30, 2009, as compared to the same periods in 2008. The change in the average price realized reflects changes in average spot market prices and the effects of our price hedging activities. We periodically enter into various hedging and other financial arrangements with respect to a portion of our projected natural gas and crude oil production in order to ensure certain desired levels of cash flow and to minimize the impact of price fluctuations, including fluctuations in locational market differentials (we refer you to Item 3 and Note 6 to the unaudited condensed consolidated financial statements included in this Form 10-Q for additional discussion).

Our hedging activities increased the average gas price $2.21 per Mcf for the three months ended September 30, 2009 compared to a decrease of $0.26 per Mcf for the same period in 2008. Our hedging activities increased the average gas price $2.15 per Mcf for the nine months ended September 30, 2009 compared to a decrease of $0.64 per Mcf for the same period in 2008. We had protected approximately 65% of our gas production for the nine months ended September 30, 2009 from the impact of widening basis differentials through our hedging activities and sales arrangements. Additionally, as of October 27, 2009, we have protected basis on approximately 50 Bcf of our remaining 2009 expected gas production through hedging activities and sales arrangements at a basis differential to NYMEX gas prices of approximately $0.25 per Mcf, excluding transportation charges and fuel charges. Disregarding the impact of hedges, the average price received for our gas production for the nine months ended September 30, 2009 was approximately $0.77 lower than average NYMEX spot prices, which represented the average locational basis differential. We typically sell our natural gas at a discount to NYMEX spot prices as a result of locational basis differentials, transportation and fuel charges.

As of October 27, 2009, we had NYMEX fixed price hedges in place on notional volumes of 15.0 Bcf of our remaining 2009 gas production at an average price of $8.41 per MMBtu and collars in place on notional volumes of 18.0 Bcf of our remaining 2009 gas production at an average floor and ceiling price of $8.42 and $11.04 per MMBtu, respectively.

As of October 27, 2009, we had NYMEX fixed price hedges in place on notional volumes of 36.0 Bcf of our 2010 gas production and 30.0 Bcf of our 2011 gas production and collars in place on notional volumes of 14.0 Bcf of our 2010 gas production. Additionally, we have basis swaps on 22.1 Bcf for the remainder of 2009, 46.5 Bcf for 2010 and 9.0 Bcf for 2011, in order to reduce the effects of widening market differentials on prices we receive.

Operating Income

Operating income from our E&P segment was down 39% to $172.0 million for the three months ended September 30, 2009 compared to $280.6 million for the same period in 2008. The $108.6 million decrease in operating income was the result of a 19% decrease in revenues, as the revenue impact of the decline in gas prices more than offset the effect of the growth in our production volumes, and a 12% increase in operating costs and expenses. We recorded an operating loss from our E&P segment of $381.4 million for the nine months ended September 30, 2009, which represents a decline of $1,042.8 million, or 158%, from the same period in 2008. The $1,042.8 million decrease in operating income was the result of a $907.8 million non-cash ceiling test impairment recorded in the first quarter resulting from lower natural gas prices, an increase in other operating costs and expenses of $108.9 million, or 22%, resulting from our significant production growth and a net decrease in revenue of $26.1 million, or 2%, as the decline in gas prices more than offset the effect of the growth in our production volumes during the period.

Operating Costs and Expenses

Lease operating expenses per Mcfe for our E&P segment were $0.76 for the three months ended September 30, 2009 compared to $0.96 for the same period in 2008. Lease operating expenses per Mcfe for our E&P segment were also $0.76 for the nine months ended September 30, 2009 compared to $0.90 for the same period in 2008. The decreases primarily resulted from lower natural gas prices which decreased the cost of compressor fuel.

General and administrative expenses per Mcfe were $0.38 for the three months ended September 30, 2009, up from $0.33 for the same period in 2008 primarily due to a $5.4 million increase in accrued employee incentive compensation expense which was only partially offset by the effects of our increased production volumes. In total, general and administrative expenses for our E&P segment were $27.6 million for the three months ended September 30, 2009

compared to $17.2 million for the same period in 2008. Payroll, employee incentive compensation, and other employee-related costs increased by $7.9 million as a result of the expansion of our E&P operations in the Fayetteville Shale play.

General and administrative expenses per Mcfe decreased 11% to $0.34 for the nine months ended September 30, 2009 compared to the same period in 2008, reflecting the effects of our increased production volumes. In total, general and administrative expenses for our E&P segment were $72.3 million for the nine months ended September 30, 2009 compared to $52.1 million for the same period in 2008. The increase was primarily due to a $14.8 million increase in payroll, employee incentive compensation and other employee-related costs associated with the expansion of our E&P operations in the Fayetteville Shale play.

Taxes other than income taxes per Mcfe decreased to $0.10 for the three and nine months ended September 30, 2009 compared to $0.15 for the same periods in 2008.
Taxes other than income taxes per Mcfe vary from period to period due to changes in severance and ad valorem taxes that result from the mix of our production volumes and fluctuations in commodity prices. Effective January 1, 2009, the State of Arkansas increased the severance tax on natural gas wells, new discovery gas wells and gas wells that produce below a specified level. The new severance tax rates increase the severance taxes we pay with respect to all of our production within the State of Arkansas, including our Fayetteville Shale operations, and impacted our results of operations by increasing taxes other than income by $1.6 million or $0.02 per Mcfe for the three months ended September 30, 2009 compared to the same period in 2008, and by $7.3 million or $0.03 per Mcfe for the nine months ended September 30, 2009 compared to the same period in 2008.

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