NEWS RELEASE  

SOUTHWESTERN ENERGY ANNOUNCES THIRD QUARTER 2012

FINANCIAL AND OPERATING RESULTS

Houston, Texas – November 1, 2012...Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the third quarter of 2012. Highlights include:

·

Gas and oil production of 144.3 Bcfe, up 12% compared to prior year

·

Adjusted net income of $131.8 million, which excludes a non-cash ceiling test impairment of natural gas and oil properties (a non-GAAP measure reconciled below)

·

Net cash provided by operating activities before changes in operating assets and liabilities of $416.6 million (reconciled below)

For the third quarter of 2012, Southwestern reported a net loss of $144.8 million, or $0.42 per diluted share. The net loss for the three months ended September 30, 2012 included a $441.5 million non-cash ceiling test impairment ($276.6 million net of taxes) of the company’s natural gas and oil properties resulting from lower natural gas prices. Excluding the non-cash impairment, Southwestern reported net income for the third quarter of 2012 of $131.8 million (reconciled below), or $0.38 per diluted share, compared to net income of $175.2 million, or $0.50 per diluted share, for the prior year period.

Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was $416.6 million for the third quarter of 2012, down compared to $472.6 million for the same period in 2011 primarily due to lower realized gas prices.

“The main drivers of our business continue to move in the right directions,” remarked Steve Mueller, President and Chief Executive Officer of Southwestern Energy. “NYMEX gas prices are improving from the lows seen earlier in the year and our production growth, hedge position and low cost structure all contributed to increasing earnings and cash flow. The Fayetteville Shale costs are lower while well results are better and our Marcellus continued its rapid ascent in activity and production. We also have several New Ventures projects underway and look forward to learning more about the Brown Dense later in the year and will have more results from our Colorado and Montana plays in the first quarter of 2013.”

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Third Quarter 2012 Financial Results

E&P Segment – Excluding the non-cash impairment, operating income from the company’s E&P segment (reconciled below) was $145.4 million for the three months ended September 30, 2012, compared to $228.5 million for the same period in 2011. The decrease was primarily due to lower realized natural gas prices and increased operating costs and expenses from higher activity levels, partially offset by higher production.

Southwestern accounts for its natural gas and oil properties using the full-cost method of accounting, which requires the company to perform a ceiling test that limits the amount of its capitalized gas and oil properties less accumulated amortization and related deferred income taxes to the aggregate of the present value of future net revenues attributable to proved natural gas and oil reserves, net of taxes, discounted at 10 percent plus the lower of cost or market value of unproved properties. The company’s non-cash ceiling test impairment used the average quoted price from the first day of each month from the previous 12 months for Henry Hub natural gas of $2.83 per MMBtu and $91.48 per barrel for West Texas Intermediate oil, adjusted for market differentials, compared to $4.12 per MMBtu and $92.71 per barrel for West Texas Intermediate oil, adjusted for market differentials, at December 31, 2011.

Gas and oil production totaled 144.3 Bcfe in the third quarter of 2012, up 12% from 128.9 Bcfe in the third quarter of 2011, and included 123.6 Bcf from the company’s Fayetteville Shale play, up from 111.9 Bcf in the third quarter of 2011. Production from the Marcellus Shale was 15.1 Bcf in the third quarter of 2012, compared to 7.4 Bcf in the third quarter of 2011.

Including the effect of hedges, Southwestern’s average realized gas price in the third quarter of 2012 was $3.40 per Mcf, down 21% from $4.30 per Mcf in the third quarter of 2011. The company’s commodity hedging activities increased its average gas price by $1.05 per Mcf during the third quarter of 2012, compared to an increase of $0.59 per Mcf during the same period in 2011. As of September 30, 2012, Southwestern had NYMEX price hedges in place on notional volumes of approximately 67 Bcf of its remaining 2012 forecasted gas production hedged at an average floor price of $5.16 per Mcf and approximately 186 Bcf of its 2013 forecasted gas production hedged at an average floor price of $5.06 per Mcf. As of September 30, 2012, the company had protected approximately 73 Bcf of its remaining 2012 expected gas production from the potential of widening basis differentials through hedging activities and sales arrangements at an average basis differential to NYMEX gas prices of approximately ($0.03) per Mcf.

The company typically sells its natural gas at a discount to NYMEX settlement prices. This discount includes a basis differential, third-party transportation charges and fuel charges. Disregarding the impact of commodity price hedges, the company’s average price received for its gas production during the third quarter of 2012 was approximately $0.46 per Mcf lower than average NYMEX settlement prices, compared to approximately $0.49 per Mcf lower during the third quarter of 2011. In 2012, the

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company expects its total gas sales discount to NYMEX to be approximately $0.50 per Mcf.

Lease operating expenses per unit of production for the company’s E&P segment were $0.79 per Mcfe in the third quarter of 2012, compared to $0.86 per Mcfe in the third quarter of 2011. The decrease was primarily due to lower compression costs and salt water disposal costs in the Fayetteville Shale play.

General and administrative expenses per unit of production were $0.21 per Mcfe in the third quarter of 2012, compared to $0.25 per Mcfe in the third quarter of 2011. The decrease was primarily due to decreased personnel costs and professional fees.

Taxes other than income taxes per unit of production were $0.09 per Mcfe in the third quarter of 2012, compared to $0.11 per Mcfe in the third quarter of 2011. Taxes other than income taxes vary due to changes in severance and ad valorem taxes that result from the mix of the company’s volumes and fluctuations in commodity prices.

The company’s full cost pool amortization rate was $1.28 per Mcfe for both the third quarters of 2012 and 2011, respectively. The amortization rate is impacted by the timing and amount of reserve additions and the costs associated with those additions, revisions of previous reserve estimates due to both price and well performance, write-downs that result from full cost ceiling tests, proceeds from the sale of properties that reduce the full cost pool and the levels of costs subject to amortization. The company cannot predict its future full cost pool amortization rate with accuracy due to the variability of each of the factors discussed above, as well as other factors.

Midstream Services – Operating income for the company’s Midstream Services segment, which is comprised of natural gas gathering and marketing activities, was $75.5 million for the three months ended September 30, 2012, up 13% from $66.8 million in the same period in 2011. The increase in operating income was primarily due to increased gathering revenues related to the company’s Fayetteville and Marcellus Shale properties, partially offset by increased operating costs and expenses. At September 30, 2012, the company’s midstream segment was gathering approximately 2.2 Bcf per day through 1,837 miles of gathering lines in the Fayetteville Shale play, compared to gathering approximately 2.0 Bcf per day a year ago. Gathering volumes, revenues and expenses for this segment are expected to grow over the next few years largely as a result of increased development of the company’s acreage in the Fayetteville Shale and Marcellus Shale and the increased development activity undertaken by other operators in those areas.

First Nine Months of 2012 Financial Results

For the first nine months of 2012, Southwestern reported a net loss of $525.2 million, or $1.51 per diluted share. Excluding non-cash ceiling test impairments recorded in the second and third quarter of 2012, the company reported adjusted net income for the first nine months of 2012 of $330.3 million (reconciled below), or $0.95 per diluted share, compared to $479.2 million, or $1.37 per diluted share, for the first nine months of 2011. Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was approximately $1.1 billion for the first nine months of 

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2012, compared to approximately $1.3 billion for the same period in 2011.

E&P Segment – Excluding the non-cash impairment, operating income from the company’s E&P segment (reconciled below) was $337.6 million for the nine months ended September 30, 2012, compared to $629.3 million for the same period in 2011. The decrease was primarily due to lower average realized gas prices and increased operating costs and expenses from higher activity levels which were partially offset by higher production volumes.

Gas and oil production was 415.1 Bcfe in the first nine months of 2012, up 13% compared to 366.7 Bcfe in the first nine months of 2011, and included 360.4 Bcf from the company’s Fayetteville Shale play, up from 320.4 Bcf in the first nine months of 2011. Production from the Marcellus Shale was 34.3 Bcf in the first nine months of 2012, compared to 15.2 Bcf in the first nine months of 2011. The company expects its full-year production for 2012 to range between approximately 560 and 570 Bcfe, an increase of approximately 13% compared to 2011 (using midpoints).

Southwestern’s average realized gas price was $3.34 per Mcf, including the effect of hedges, in the first nine months of 2012 down 21% compared to $4.24 per Mcf in the first nine months of 2011. The company’s hedging activities increased the average gas price realized during the first nine months of 2012 by $1.22 per Mcf, compared to an increase of $0.49 per Mcf during the first nine months of 2011. Disregarding the impact of hedges, the average price received for the company’s gas production during the first nine months of 2012 was approximately $0.47 per Mcf lower than average monthly NYMEX settlement prices, compared to approximately $0.46 per Mcf during the first nine months of 2011.

Lease operating expenses for the company’s E&P segment were $0.80 per Mcfe in the first nine months of 2012, compared to $0.84 per Mcfe in the first nine months of 2011. The decrease was primarily due to lower compression costs in the Fayetteville Shale.

General and administrative expenses were $0.26 per Mcfe in both the first nine months of 2012 and 2011, respectively.

Taxes other than income taxes were $0.10 per Mcfe during the first nine months of 2012, compared to $0.11 per Mcfe during the first nine months of 2011.

The company’s full cost pool amortization rate increased to $1.33 per Mcfe in the first nine months of 2012, compared to $1.29 per Mcfe in the first nine months of 2011.

Midstream Services - Operating income for the company’s midstream activities was $216.6 million in the first nine months of 2012, up 20% compared to $180.4 million in the first nine months of 2011. The increase in operating income was primarily due to increased gathering revenues related to the company’s Fayetteville and Marcellus Shale properties, partially offset by increased operating costs and expenses.

Capital Structure and Investments – At September 30, 2012, the company had approximately $1.7 billion in long-term debt and its total debt-to-total capitalization was 34.3%, compared to 25.3% at December 31, 2011. The company also had cash and

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cash equivalents and restricted cash of approximately $145.6 million at September 30, 2012.

Southwestern invested a total of approximately $1.6 billion during both the first nine months of 2012 and 2011, respectively. The company’s 2012 capital investment program included $1.5 billion invested in its E&P business and $106 million invested in its Midstream Services activities. Southwestern’s total capital investments program for 2012 is expected to be approximately $2.1 billion.

E&P Operations Review

Southwestern invested approximately $1.5 billion in its E&P business during the first nine months of 2012, of which approximately $832 million was invested in its Fayetteville Shale play, $368 million in the Marcellus Shale, $231 million in New Ventures, $11 million in Ark-La-Tex and $12 million in E&P Services.

Fayetteville Shale Play – For the third quarter of 2012, Southwestern placed a total of 105 operated wells on production in the Fayetteville Shale play, all of which were horizontal wells fracture stimulated using slickwater. At September 30, 2012, the company’s gross production rate from the Fayetteville Shale play was approximately 2.0 Bcf per day, up from approximately 1.9 Bcf per day a year ago. The company is currently utilizing 11 drilling rigs in its Fayetteville Shale play, including 7 that are capable of drilling horizontal wells. The graph below provides gross production data from the company’s operated wells in the Fayetteville Shale play area through September 30, 2012.

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During the third quarter of 2012, the company’s horizontal wells had an average completed well cost of $2.6 million per well, average horizontal lateral length of 4,974 feet and average time to drill to total depth of 6.8 days from re-entry to re-entry. This compares to an average completed well cost of $2.8 million per well, average horizontal lateral length of 4,840 feet and average time to drill to total depth of 6.9 days from re-entry to re-entry in the second quarter of 2012. In the third quarter of 2012, the company had 32 operated wells placed on production which had average times to drill to total depth of 5 days or less from re-entry to re-entry. In total, the company has had a total of 192 wells drilled to total depth of 5 days or less from re-entry to re-entry.

The company’s wells placed on production during the third quarter of 2012 averaged initial production rates of 3,857 Mcf per day. Results from the company’s drilling activities from 2007 by quarter are shown below.

Time Frame	Wells Placed on Production	Average IP Rate (Mcf/d)	30th-Day Avg Rate (# of wells)	60th-Day Avg Rate (# of wells)	Average Lateral Length
1st Qtr 2007	58	1,261	1,066 (58)	958 (58)	2,104
2nd Qtr 2007	46	1,497	1,254 (46)	1,034 (46)	2,512
3rd Qtr 2007	74	1,769	1,510 (72)	1,334 (72)	2,622
4th Qtr 2007	77	2,027	1,690 (77)	1,481 (77)	3,193
1st Qtr 2008	75	2,343	2,147 (75)	1,943 (74)	3,301
2nd Qtr 2008	83	2,541	2,155 (83)	1,886 (83)	3,562
3rd Qtr 2008	97	2,882	2,560 (97)	2,349 (97)	3,736
4th Qtr 2008(1)	74	3,350(1)	2,722 (74)	2,386 (74)	3,850
1st Qtr 2009(1)	120	2,992(1)	2,537 (120)	2,293 (120)	3,874
2nd Qtr 2009	111	3,611	2,833 (111)	2,556 (111)	4,123
3rd Qtr 2009	93	3,604	2,624 (93)	2,255 (93)	4,100
4th Qtr 2009	122	3,727	2,674 (122)	2,360 (120)	4,303
1st Qtr 2010(2)	106	3,197(2)	2,388 (106)	2,123 (106)	4,348
2nd Qtr 2010	143	3,449	2,554 (143)	2,321 (142)	4,532
3rd Qtr 2010	145	3,281	2,448 (145)	2,202 (144)	4,503
4th Qtr 2010	159	3,472	2,678 (159)	2,294 (159)	4,667
1st Qtr 2011	137	3,231	2,604 (137)	2,238(137)	4,985
2nd Qtr 2011	149	3,014	2,328 (149)	1,991 (149)	4,839
3rd Qtr 2011	132	3,443	2,666 (132)	2,372 (132)	4,847
4th Qtr 2011	142	3,646	2,606 (142)	2,243 (142)	4,703
1st Qtr 2012	146	3,319	2,421 (146)	2,131 (146)	4,743
2nd Qtr 2012	131	3,500	2,515 (131)	2,225 (131)	4,840
3rd Qtr 2012	105	3,857	2,579 (79)	2,157(43)	4,974

Note: Results as of September 30, 2012.  

(1)

The significant increase in the average initial production rate for the fourth quarter of 2008 and the subsequent decrease for the first quarter of 2009 primarily reflected the impact of the delay in the Boardwalk Pipeline.  

(2)

In the first quarter of 2010, the company’s results were impacted by the shift of all wells to “green completions” and the mix of wells, as a large percentage of wells were placed on production in the shallower northern and far eastern borders of the company’s acreage.

Marcellus Shale – In northeast Pennsylvania, Southwestern had 50 horizontal producing wells,44 wells waiting on either completion or pipeline and 34 wells in progress at September 30, 2012. The company is currently utilizing four drilling rigs in the Marcellus Shale.

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Net production from the area was 15.1 Bcf in the third quarter of 2012, compared to 7.4 Bcf in the third quarter of 2011. At September 30, 2012, the company’s gross operated production from the area was approximately 218 MMcf per day. In Susquehanna County, the company currently has approximately 25 wells currently waiting on either completion or the Bluestone Pipeline, which is estimated to be placed into service into the TGP 300 Pipeline in late-November. Once the Bluestone Pipeline is in-service, the company expects that its year-end gross production exit rate will be approximately 300 million cubic feet of gas per day.

The graph below provides normalized average daily production data through September 30, 2012, for the company’s horizontal wells in the Marcellus Shale. The “purple curve” indicates results for 22 wells with more than 12 fracture stimulation stages, the “orange curve” indicates results for 27 wells with 9 to 12 fracture stimulation stages and the “green curve” indicates results for 1 well with less than 9 fracture stimulation stages. The normalized production curves are intended to provide a qualitative indication of the company’s Marcellus Shale wells’ performance and should not be used to estimate an individual well’s estimated ultimate recovery. The 4, 6, 8 and 10 Bcf typecurves are shown solely for reference purposes and are not intended to be projections of the performance of the company’s wells.

Ark-La-Tex – Total net production from the company’s East Texas and conventional Arkoma Basin properties was 5.7 Bcfe in the third quarter of 2012, compared to 9.6 Bcfe in the third quarter of 2011.

On May 1, 2012, Southwestern sold its oil and natural gas leases, wells and gathering equipment in its Overton Field in East Texas for approximately $168 million, excluding typical purchase price adjustments. The sale includes approximately 19,800 net acres in

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Smith County, Texas. Net production from the field was approximately 24 MMcfe per day as of the closing date and proved net reserves were approximately 143 Bcfe as of year-end 2011.

New Ventures – The company holds 3,814,400 net undeveloped acres in connection with its New Ventures prospects, of which 2,518,518 net acres were located in New Brunswick, Canada.

Southwestern has approximately 506,000 net acres targeting the Lower Smackover Brown Dense formation in southern Arkansas and northern Louisiana. The company has drilled six wells in the play area to date. The company’s first three wells, which were completed earlier this year, are currently shut-in. The company’s fourth and fifth wells, the Johnson #21-22-1 #1 and the Dean 31-22-1E #1 both located in Union Parish, Louisiana, were drilled to vertical depths of 10,507 feet and 10,503 feet, respectively. Both wells encountered higher pressures within the target formation and the company is using these wells to obtain additional log data and core samples and to optimize fracture stimulation designs in the vertical sections of the wells. The company currently plans to re-enter these wells as horizontal wells in 2013. The company is also completing the Doles 30-22-1H #1, located in Union Parish, Louisiana, which was drilled to approximately 10,673 feet with a 4,731-foot completed horizontal lateral. This well also encountered high pressure within the formation and flowback is planned during the first week in November. In late-November, the company plans to place both the Doles well and the company’s third well, the BML #31-22 #1-1H, to sales with the expectation of learning more about the decline characteristics of both wells before year-end. Southwestern has permitted and plans to drill additional wells in the area in 2013.

The company has approximately 302,000 net acres in the Denver-Julesburg Basin in eastern Colorado where the company has begun testing a new unconventional oil play targeting middle and late Pennsylvanian to Permian age carbonates and shales. The company has completed a horizontal well and a vertical well, both of which are testing multiple intervals. Evaluation will continue on these two wells over the next 90 days. Southwestern is permitting and plans to drill additional wells in the area in 2013.

The company has also drilled and completed a well in Sheridan County, Montana, targeting the Bakken/Three Forks objectives, which has been flowing back for approximately 60 days. The company is continuing to lease acreage and plans to permit and drill additional wells in the area in 2013.

Explanation and Reconciliation of Non-GAAP Financial Measures

The company reports its financial results in accordance with accounting principles generally accepted in the United States of America (“GAAP”). However, management believes certain non-GAAP performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of its peers and of prior periods.  

One such non-GAAP financial measure is net cash provided by operating activities before changes in operating assets and liabilities. Management presents this measure because (i) it is accepted as an indicator of an oil and gas exploration and production

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company’s ability to internally fund exploration and development activities and to service or incur additional debt, (ii) changes in operating assets and liabilities relate to the timing of cash receipts and disbursements which the company may not control and (iii) changes in operating assets and liabilities may not relate to the period in which the operating activities occurred.

Additional non-GAAP financial measures the company may present from time to time are net income, diluted earnings per share and its E&P segment operating income, all which exclude certain charges or amounts. Management presents these measures because (i) they are consistent with the manner in which the company’s performance is measured relative to the performance of its peers, (ii) these measures are more comparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by the company excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

See the reconciliations below of GAAP financial measures to non-GAAP financial measures for the three and nine months ended September 30, 2012 and September 30, 2011. Non-GAAP financial measures should not be considered in isolation or as a substitute for the company's reported results prepared in accordance with GAAP.

	3 Months Ended Sept. 30,
	2012	2011
	(in thousands)
Net income (loss):
Net income (loss)	$ (144,815)	$ 175,173
Add back:
Impairment of natural gas and oil properties (net of taxes)	276,644	--
Net income, excluding impairment of natural gas and oil properties	$ 131,829	$ 175,173

	9 Months Ended Sept. 30,
	2012	2011
	(in thousands)
Net income (loss):
Net income (loss)	$ (525,211)	$ 479,236
Add back:
Impairment of natural gas and oil properties (net of taxes)	855,522	--
Net income, excluding impairment of natural gas and oil properties	$ 330,311	$ 479,236

	3 Months Ended Sept. 30,
	2012	2011
Diluted earnings per share:
Net income (loss) per share	$ (0.42)	$ 0.50
Add back:
Impairment of natural gas and oil properties (net of taxes)	0.80	--
Net income per share, excluding impairment of natural gas and oil properties	$ 0.38	$ 0.50

	9 Months Ended Sept. 30,
	2012	2011
Diluted earnings per share:
Net income (loss) per share	$ (1.51)	$ 1.37
Add back:
Impairment of natural gas and oil properties (net of taxes)	2.46	--
Net income per share, excluding impairment of natural gas and oil properties	$ 0.95	$ 1.37

	3 Months Ended Sept. 30,
	2012	2011
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 355,087	$ 443,281
Add back (deduct):
Change in operating assets and liabilities	61,523	(29,313)
Net cash provided by operating activities before changes   in operating assets and liabilities	$ 416,610	$ 472,594

	9 Months Ended Sept. 30,
	2012	2011
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 1,192,477	$ 1,300,211
Add back (deduct):
Change in operating assets and liabilities	(50,520)	12,129
Net cash provided by operating activities before changes   in operating assets and liabilities	$ 1,141,957	$ 1,312,340

	3 Months Ended Sept. 30,
	2012	2011
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$ (296,108)	$ 228,476
Add back:
Impairment of natural gas and oil properties	441,465	--
E&P segment operating income excluding impairment   of natural gas and oil properties	$ 145,357	$ 228,476

	9 Months Ended Sept. 30,
	2012	2011
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$ (1,039,737)	$ 629,298
Add back:
Impairment of natural gas and oil properties	1,377,364	--
E&P segment operating income excluding impairment   of natural gas and oil properties	$ 337,627	$ 629,298

Southwestern will host a teleconference call on Friday, November 2, 2012, at 10:00

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a.m. Eastern to discuss the company’s third quarter 2012 results. The toll-free number to call is 877-407-8035 and the international toll-free number is 201-689-8035. The teleconference can also be heard “live” on the Internet at http://www.swn.com.

Southwestern Energy Company is an independent energy company whose wholly-owned subsidiaries are engaged in oil and gas exploration and production, natural gas gathering and marketing. Additional information on the company can be found on the Internet at http://www.swn.com.

Contacts:

R. Craig Owen

Brad D. Sylvester, CFA

Senior Vice President

            Vice President, Investor Relations

and Chief Financial Officer

            (281) 618-4897

(281) 618-2808

All statements, other than historical facts and financial information, may be deemed to be forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements that address activities, outcomes and other matters that should or may occur in the future, including, without limitation, statements regarding the financial position, business strategy, production and reserve growth and other plans and objectives for the company’s future operations, are forward-looking statements. Although the company believes the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance and actual results or developments may differ materially from those in the forward-looking statements. The company has no obligation and makes no undertaking to publicly update or revise any forward-looking statements, other than to the extent set forth below. You should not place undue reliance on forward-looking statements. They are subject to known and unknown risks, uncertainties and other factors that may affect the company’s operations, markets, products, services and prices and cause its actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with forward-looking statements, risks, uncertainties and factors that could cause the company’s actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: the timing and extent of changes in market conditions and prices for natural gas and oil (including regional basis differentials); the company’s ability to transport its production to the most favorable markets or at all; the timing and extent of the company’s success in discovering, developing, producing and estimating reserves; the economic viability of, and the company’s success in drilling, the company’s large acreage position in the Fayetteville Shale play, overall as well as relative to other productive shale gas areas; the company’s ability to fund the company’s planned capital investments; the impact of federal, state and local government regulation, including any legislation relating to hydraulic fracturing, the climate or over the counter derivatives; the company’s ability to determine the most effective and economic fracture stimulation for the Fayetteville Shale play and the Marcellus Shale play; the costs and availability of oil field personnel services and drilling supplies, raw materials, and equipment and services; the company’s future property acquisition or divestiture activities; increased

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competition; the financial impact of accounting regulations and critical accounting policies; the comparative cost of alternative fuels; conditions in capital markets, changes in interest rates and the ability of the company’s lenders to provide it with funds as agreed; credit risk relating to the risk of loss as a result of non-performance by the company’s counterparties and any other factors listed in the reports the company has filed and may file with the Securities and Exchange Commission (SEC). For additional information with respect to certain of these and other factors, see the reports filed by the company with the SEC. The company disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

Financial Summary Follows

# # #

OPERATING STATISTICS (Unaudited)			Page 1 of 5
Southwestern Energy Company and Subsidiaries
	Three Months		Nine Months
Periods Ended September 30,	2012	2011	2012	2011
Exploration & Production
Production
Gas production (Bcf)	144.2	128.7	414.7	366.2
Oil production (MBbls)	19	24	59	79
Total equivalent production (Bcfe)	144.3	128.9	415.1	366.7
Commodity Prices
Average gas price per Mcf, including hedges	$ 3.40	$ 4.30	$ 3.34	$ 4.24
Average gas price per Mcf, excluding hedges	$ 2.35	$ 3.71	$ 2.12	$ 3.75
Average oil price per Bbl	$ 99.67	$ 88.35	$ 102.89	$ 93.54
Operating Expenses per Mcfe
Lease operating expenses	$ 0.79	$ 0.86	$ 0.80	$ 0.84
General & administrative expenses	$ 0.21	$ 0.25	$ 0.26	$ 0.26
Taxes, other than income taxes	$ 0.09	$ 0.11	$ 0.10	$ 0.11
Full cost pool amortization	$ 1.28	$ 1.28	$ 1.33	$ 1.29
Midstream
Gas volumes marketed (Bcf)	171.2	153.3	498.7	450.4
Gas volumes gathered (Bcf)	214.7	190.9	622.9	545.7

STATEMENTS OF OPERATIONS (Unaudited)				Page 2 of 5
Southwestern Energy Company and Subsidiaries
	Three Months		Nine Months
Periods Ended September 30,	2012	2011	2012	2011
	(in thousands, except share/per share amounts)
Operating Revenues
Gas sales	$ 491,340	$ 551,770	$ 1,384,152	$ 1,544,165
Gas marketing	148,764	176,787	423,503	549,243
Oil sales	1,889	2,157	6,097	7,387
Gas gathering	43,855	36,541	128,293	107,961
	685,848	767,255	1,942,045	2,208,756
Operating Costs and Expenses
Gas purchases – midstream services	149,651	175,236	423,941	545,518
Operating expenses	61,906	63,911	179,478	175,763
General and administrative expenses	36,121	35,600	129,879	112,955
Depreciation, depletion and amortization	200,655	179,113	602,112	514,180
Impairment of natural gas and oil properties	441,465	—	1,377,364	—
Taxes, other than income taxes	16,252	17,677	51,154	49,429
	906,050	471,537	2,763,928	1,397,845
Operating Income (Loss)	(220,202)	295,718	(821,883)	810,911
Interest Expense
Interest on debt	25,463	16,696	69,154	48,380
Other interest charges	1,058	902	3,096	3,414
Interest capitalized	(15,915)	(11,941)	(45,945)	(32,531)
	10,606	5,657	26,305	19,263
Other Income (Loss), Net	238	(122)	2,615	321
Income (Loss) Before Income Taxes	(230,570)	289,939	(845,573)	791,969
Provision (Benefit) for Income Taxes
Current	101	3,491	369	3,691
Deferred	(85,856)	111,275	(320,731)	309,042
	(85,755)	114,766	(320,362)	312,733
Net income (loss)	$ (144,815)	$ 175,173	$ (525,211)	$ 479,236
Earnings Per Share
Basic	$ (0.42)	$ 0.50	$ (1.51)	$ 1.38
Diluted	$ (0.42)	$ 0.50	$ (1.51)	$ 1.37
Weighted Average Common Shares Outstanding
Basic	348,649,630	347,239,793	348,272,192	347,070,330
Diluted	348,649,630	349,998,789	348,272,192	349,891,885

BALANCE SHEETS (Unaudited)	Page 3 of 5
Southwestern Energy Company and Subsidiaries
September 30,	2012	2011
	(in thousands)
ASSETS
Current Assets	$ 846,747	$ 836,120
Property and Equipment	12,506,903	10,444,393
Less: Accumulated depreciation, depletion and amortization	(6,414,955)	(4,230,121)
	6,091,948	6,214,272
Other Assets	134,256	163,715
	$ 7,072,951	$ 7,214,107
LIABILITIES AND EQUITY
Current Liabilities	$ 761,165	$ 766,250
Long-Term Debt	1,695,342	1,271,000
Deferred Income Taxes	1,203,703	1,461,205
Other Long-Term Liabilities	159,462	107,099
Commitments and Contingencies
Equity
Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 350,415,917 shares in 2012 and 348,264,799 in 2011	3,504	3,483
Additional paid-in capital	928,322	880,425
Retained earnings	2,131,003	2,497,681
Accumulated other comprehensive income	192,040	229,750
Common stock in treasury, 66,791 shares in 2012 and 125,984 in 2011	(1,590)	(2,786)
Total Equity	3,253,279	3,608,553
	$ 7,072,951	$ 7,214,107

STATEMENTS OF CASH FLOWS (Unaudited)	Page 4 of 5
Southwestern Energy Company and Subsidiaries
	Nine Months
Periods Ended September 30,	2012	2011
	(in thousands)
Cash Flows From Operating Activities
Net income (loss)	$ (525,211)	$ 479,236
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	604,887	516,891
Impairment of natural gas and oil properties	1,377,364	—
Deferred income taxes	(320,731)	309,042
Unrealized gain on derivatives	(2,890)	905
Stock-based compensation	8,226	6,619
Other	312	(353)
Change in assets and liabilities	50,520	(12,129)
Net cash provided by operating activities	1,192,477	1,300,211
Cash Flows From Investing Activities
Capital investments	(1,623,751)	(1,543,549)
Proceeds from sale of property and equipment	201,161	121,546
Transfers to restricted cash	(167,774)	(85,040)
Transfers from restricted cash	40,700	15,779
Other	5,239	4,940
Net cash used in investing activities	(1,544,425)	(1,486,324)
Cash Flows From Financing Activities
Payments on current portion of long-term debt	(600)	(600)
Payments on revolving long-term debt	(1,774,000)	(2,575,000)
Borrowings under revolving long-term debt	1,129,000	2,753,600
Change in bank drafts outstanding	1,627	10,621
Proceeds from issuance of long-term debt	998,780	—
Debt issuance costs	(8,338)	—
Revolving credit facility costs	—	(10,211)
Proceeds from exercise of common stock options	8,422	4,844
Net cash provided by financing activities	354,891	183,254
Effect of exchange rate changes on cash	(10)	97
Increase (decrease) in cash and cash equivalents	2,933	(2,762)
Cash and cash equivalents at beginning of year	15,627	16,055
Cash and cash equivalents at end of period	$ 18,560	$ 13,293

SEGMENT INFORMATION (Unaudited)				Page 5 of 5
Southwestern Energy Company and Subsidiaries
	Exploration
	&	Midstream
	Production	Services	Other	Eliminations	Total
	(in thousands)
Quarter Ending September 30, 2012
Revenues	$ 492,223	$ 602,339	$ 849	$ (409,563)	$ 685,848
Gas purchases	—	474,628	—	(324,977)	149,651
Operating expenses	113,417	32,221	56	(83,788)	61,906
General & administrative expenses	30,256	6,615	48	(798)	36,121
Depreciation, depletion & amortization	189,714	10,620	321	—	200,655
Impairment of natural gas and oil properties	441,465	—	—	—	441,465
Taxes, other than income taxes	13,479	2,767	6	—	16,252
Operating Income (Loss)	$ (296,108)	$ 75,488	$ 418	$ —	$ (220,202)
Capital Investments (1)	$ 385,585	$ 31,693	$ 7,608	$ —	$ 424,886
Quarter Ending September 30, 2011
Revenues	$ 555,620	$ 743,831	$ 832	$ (533,028)	$ 767,255
Gas purchases	—	629,899	—	(454,663)	175,236
Operating expenses	111,444	30,001	34	(77,568)	63,911
General & administrative expenses	32,615	3,718	64	(797)	35,600
Depreciation, depletion & amortization	169,391	9,414	308	—	179,113
Taxes, other than income taxes	13,694	3,962	21	—	17,677
Operating Income	$ 228,476	$ 66,837	$ 405	$ —	$ 295,718
Capital Investments (1)	$ 421,182	$ 32,158	$ 17,095	$ —	$ 470,435
Nine Months Ending September 30, 2012
Revenues	$ 1,388,440	$ 1,637,188	$ 2,552	$ (1,086,135)	$ 1,942,045
Gas purchases	—	1,267,117	—	(843,176)	423,941
Operating expenses	332,588	87,298	163	(240,571)	179,478
General & administrative expenses	107,604	24,482	181	(2,388)	129,879
Depreciation, depletion & amortization	568,654	32,499	959	—	602,112
Impairment of natural gas and oil properties	1,377,364	—	—	—	1,377,364
Taxes, other than income taxes	41,967	9,194	(7)	—	51,154
Operating Income (Loss)	$ (1,039,737)	$ 216,598	$ 1,256	$ —	$ (821,883)
Capital Investments (1)	$ 1,450,569	$ 105,576	$ 30,486	$ —	$ 1,586,631
Nine Months Ending September 30, 2011
Revenues	$ 1,561,658	$ 2,183,708	$ 2,401	$ (1,539,011)	$ 2,208,756
Gas purchases	—	1,862,736	—	(1,317,218)	545,518
Operating expenses	308,665	86,478	53	(219,433)	175,763
General & administrative expenses	96,667	18,449	199	(2,360)	112,955
Depreciation, depletion & amortization	486,130	27,170	880	—	514,180
Taxes, other than income taxes	40,898	8,477	54	—	49,429
Operating Income	$ 629,298	$ 180,398	$ 1,215	$ —	$ 810,911
Capital Investments (1)	$ 1,365,434	$ 137,998	$ 53,506	$ —	$ 1,556,938

(1)

Capital investments include decreases of $56.2 million and $60.9 million for the three-month periods ended September 30, 2012 and 2011, respectively, and decreases of $40.7 million and $3.0 million for the nine-month periods ended September 30, 2012 and 2011, respectively, relating to the change in accrued expenditures between periods.