NEWS RELEASE

SOUTHWESTERN ENERGY ANNOUNCES THIRD QUARTER 2013

FINANCIAL AND OPERATING RESULTS

Houston, Texas – October 31, 2013...Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the threemonths ended September 30, 2013.  Highlights include:

· Record gas and oil production of 172.4 Bcfe, up 19%  compared to year-ago levels

· 2013 production guidance raised to 653 to 655 Bcfe, up from 643 to 651 previously

· Adjusted net income of $179.8 million, up 36%  compared to year-ago levelswhen excludingunrealized net gains and losses on derivative contracts and non-cash ceiling test impairments of natural gas and oil properties(anon-GAAP measure reconciled below)

· Record net cash provided by operating activities before changes in operating assets and liabilities of approximately $526.7million,  up 26%  compared to year-ago levels(a non-GAAP measure reconciled below)

· Marcellus Shale production up 196% compared to year-ago levels; gross operated production surpasses600 MMcf per day; additional firm transportation capacity secured currently totals over 1 Bcf per day by year-end 2015

· Record well initial production rate of 10 MMcf per day in the Fayetteville Shale

· Vertical well in Lower Smackover Brown Dense exploration program produces 600 barrels of oil per day

“We had a  very good third quarter, fueled by our record production,which resulted in the highest quarterly cash flow ever for Southwestern Energy,” remarked Steve Mueller, President and Chief Executive Officer of Southwestern Energy. “Our production growth from the Marcellus Shale was outstanding, as gross production reached a new milestone of 600 MMcf of gas per dayand net production was up 32% sequentially.  In addition, we continue to improve our completion techniques and flowback procedures in the Fayetteville Shale which have also resulted in new milestones, the greatest of which is surpassing the 3 Tcf cumulative gross operated production milestone on September 16, which is almost exactly 9 years to the day we commenced first production from the Fayetteville in 2004. Finally, in our Lower Smackover Brown Dense project we drilled our best well to date which reached a peak rate of 600 barrels of oil per day and 1.3MMcf of gas per day, or over 800 barrels of oil equivalent per day. We will be drilling and completing three additional vertical wells in 2013 to test more of this project.  We believe our curiosity and innovation will keep driving us higher up the learning curve as we work to unlock more value from these resource plays.”

- MORE -

Third Quarter of 2013 Financial Results

For the third quarter of 2013, Southwestern reported net income of $185.9 million, or $0.53per diluted share, compared to a  net loss of $54.1 million, or $0.16 per diluted share in the third quarter of 2012.  Net income also included a non-cash unrealized net gain of $10.1 million ($6.1 million net of taxes) on derivative contracts associated with the company’s hedging program.  Excluding this non-cash item, Southwestern reported adjusted net income for the thirdquarter of 2013 of $179.8 million (reconciled below), or $0.51per diluted share.The net loss for the three months ended September 30, 2012 included a $289.8 million non-cash ceiling test impairment ($185.7 million net of taxes) of the company’s natural gas and oil properties resulting from lower natural gas prices and a  non-cash unrealized net loss of  $1.1million ($0.7 million net of taxes)on derivative contracts associated with the company’s hedging program. Excluding the non-cash impairment and unrealized loss, Southwestern reported adjusted net income for the third quarter of 2012 of $132.3 million, or $0.38 per diluted share.

Net cash provided by operating activities before changes in operating assets and liabilities(reconciled below) was a record $526.7million for the thirdquarter of 2013,  up 26%  compared to  $416.6million for the same period in 2012.

E&P Segment–  Operating income from the company’s E&P segmentwas $222.7million for the three months ended September 30, 2013,  compared to $148.0million for the three months ended September 30, 2012 (reconciled below). The increase was primarily due to higher production volumesand higher realized natural gas prices, partially offset by higher operating costs and expenses due to increased activity levels.

Gas and oil production totaled 172.4 Bcfe in the third quarter of 2013, up 19% from 144.3Bcfe in the third quarter of 2012, and included 122.7 Bcf from the company’s Fayetteville Shale play,  compared to123.6Bcf in the third quarter of 2012. Production from the Marcellus Shale was 44.7 Bcf in the third quarter of 2013, compared to 15.1 Bcf in the third quarter of 2012.The companycurrently expects its total gas and oil production for 2013 to range between of 653 to 655Bcfe,  an increase of approximately 16% over the company’s 2012 gas and oil production (using midpoints). The company’s production guidance for the remainder of 2013 is as follows:

	1st Quarter Actual	2nd Quarter Actual	3rd Quarter Actual	4th Quarter Estimate	Full-Year 2013 Estimate
Previous Guidance(Bcfe)	147.8	160.1	164 - 168	171 - 175	643 - 651
New Guidance(Bcfe)	147.8	160.1	172.4	173- 175	653 - 655

- MORE -

Southwestern’s average realized gas price in the thirdquarter of 2013 was $3.60per Mcf, up from $3.41 per Mcf in the third quarter of 2012. The company’s commodity hedging activities increased its average gas price by $0.54per Mcf during the thirdquarter of 2013, compared to an increase of $1.06 per Mcf during the same period in 2012. As of October31, 2013,  the company had approximately 84 Bcf of its remaining 2013expected gas production hedged at an average price of $4.68per Mcf and approximately 233Bcf of its 2014 forecasted gas production hedged at an average price of $4.41per Mcf.As of September 30, 2013, the company had protected approximately 74Bcf of its remaining 2013 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 ($0.06) 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 hedges, the company’s average price received for its gas production during the third quarter of 2013 was approximately $0.52per Mcf lower than average NYMEX settlement prices, compared to approximately $0.46 per Mcf lower during the third quarter of 2012.  For the fourth quarter of 2013, the company expectsits total natural gas sales discount to NYMEX to be approximately $0.55 per Mcf.

Lease operating expenses per unit of production for the company’s E&P segment were $0.87per Mcfe in the third quarter of 2013, compared to $0.79 per Mcfe in the thirdquarter of 2012. The increase was primarily due to increased third-party compression and gathering costs in the Marcellus Shaleand higher activity levels, offset slightly by a decrease in salt water disposal costs in the Fayetteville Shale.

General and administrative expenses per unit of production were $0.24per Mcfe in the third quarter of 2013,  compared to $0.21 per Mcfe in the third quarter of 2012.  The increase was primarily due to higherpersonnelcosts.

Taxes other than income taxes per unit of production were $0.09per Mcfe in both of the third quarters of 2013 and 2012. 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 the company’s production volumes and fluctuations in commodity prices.

The company’s full cost pool amortization rate decreased to $1.07 per Mcfe in the thirdquarter of 2013, compared to $1.30 per Mcfe in the third quarter of 2012.  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.

- MORE -

Midstream Services– Operating income for the company’s Midstream Services segment, which is comprised of natural gas gathering and marketing activities, was $86.7 million for the three months ended September 30, 2013, up 15% from $75.5 million in the same period in 2012. The increase in operating income was primarily due to the increase in gathering activityfrom the company’s Fayetteville and Marcellus Shale properties from higher gathered volumes, partially offset by increased operating costs and expenses from higher activity.  At September 30, 2013, the company’s midstream segment was gathering approximately 2.3Bcf per day through 1,920miles of gathering lines in the Fayetteville Shale and approximately 344 MMcf per day from 89 miles of gathering lines in the Marcellus Shale. Gathering volumes, revenues and expenses for this segment are expected to grow over the next few years largely as a result of continued development of the company’s acreage in the Fayetteville Shale and Marcellus Shale and development activity undertaken by other operators in those areas.

First Nine Months of 2013 Financial Results

For the first nine months of 2013, Southwestern reported net income of $559.0million, or $1.59per diluted share, compared to a  net loss of $351.5 million, or $1.01 per diluted share, for the first nine months of 2012.Net income for the first nine months of 2013 included non-cash unrealized net gainsof $72.7 million ($43.6 million net of taxes) on derivative contracts associated with the company’s hedging program.  Excluding thisnon-cash item, Southwestern reported adjusted net income for the first nine months of 2013 of $515.5 million (reconciled below), or $1.47per diluted share.  For the first nine months of 2012, the company reported adjusted net income of  $330.0 million (reconciled below), or $0.95 per diluted share, excluding non-cash ceiling test impairments and non-cash unrealized net losseson derivative contracts associated with the company’s hedging program.

Net cash provided by operating activities before changes in operating assets and liabilities (reconciled below) was $1.4  billion for the first nine months of 2013,  up 27% from  $1.1  billion for the same period in 2012.  

E&P Segment–Operating income from the company’s E&P segment (reconciled below) was $651.0 million for the nine months ended September 30, 2013, compared to $344.9 million for the same period in 2012.  The increase was primarily due to higher production volumesand higher realized natural gas prices, partially offset by higher operating costs and expenses due to increased activity levels.

Gas and oil production was 480.3Bcfe in the first nine months of 2013,  up 16%  compared to 415.1 Bcfe in the first nine months of 2012, and included 362.8Bcf from the company’s Fayetteville Shale play, up from 360.4 Bcf in the first nine months of 2012.  Production from the Marcellus Shale was 102.1 Bcf in the first nine months of 2013, compared to 34.3 Bcf in the first nine months of 2012.

- MORE -

Southwestern’s average realized gas price was $3.63per Mcfin the first nine months of 2013, including the effect of hedges, compared to $3.33per Mcf in the first nine months of 2012. The company’s hedging activities increased the average gas price realized during the first nine months of 2013 by $0.45per Mcf, compared to an increase of $1.21per Mcf during the first nine months of 2012. Disregarding the impact of hedges, the average price received for the company’s gas production during the first nine months of 2013and 2012 was approximately $0.49 per Mcf and $0.47per Mcf lower than average monthly NYMEX settlement prices,  respectively.  

Lease operating expenses for the company’s E&P segment were $0.85per Mcfe in the first nine months of 2013,  compared to $0.80 per Mcfe in the first nine months of 2012.  The increase was primarily due to an increase in third-party gathering costsin the Marcellus Shale and higher activity levels, offset slightly by a decrease in salt water disposal costs in the Fayetteville Shale.

General and administrative expenses were $0.23per Mcfe in the first nine months of 2013, compared to $0.26 per Mcfe in the first nine months of 2012.  The decrease was primarily due to lower personnel costs.

Taxes other than income taxes were $0.10per Mcfe during both the first nine months of 2013 and2012.  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 production volumes and fluctuations in commodity prices.

The company’s full cost pool amortization rate decreased to $1.07per Mcfe in the first nine months of 2013, compared to $1.34 per Mcfe in the first nine months of 2012.

Midstream Services - Operating income for the company’s midstream activities was $235.9million in the first nine months of 2013,  up 9%  compared to $216.6million in the first nine months of 2012. The increase in operating income was primarily due to increased gathering activityrelated to the company’s Fayetteville and Marcellus Shale properties, partially offset by increased operating costs and expenses.

Capital Structure and Investments – At September 30, 2013, the company had approximately $1.9 billion in long-term debt and its long-term debt-to-total capitalization ratio was35%, compared to 35% at December 31, 2012.  The company had approximately $243million borrowed on its revolving credit facility and also had cash and cash equivalents of approximately  $19million at September 30, 2013.

For the first nine months of 2013, Southwestern invested a total of approximately $1.8  billion, compared to  $1.6 billion during the first nine months of 2012. The company’s capital investments in 2013 included $1.6  billion invested in its E&P business and $135million invested in its Midstream Services activities.

- MORE -

E&P Operations Review

Southwestern invested approximately$1.6  billion in its E&P business during the first nine months of 2013,  of which approximately $735 million was invested in the Marcellus Shale, $678 million in the Fayetteville Shale, $133million in New Ventures, $52 million in E&P Services and $5 million in Ark-La-Tex.

Marcellus Shale–  At September 30, 2013, Southwesternhad 151 operated horizontal wells on production and 80 wells in progress in the Marcellus Shale, resulting in net production of 44.7 Bcf in the third quarter of 2013,  up 196% compared to 15.1 Bcf in the thirdquarter of 2012. Gross production from the company’s operated wells in the Marcellus Shale was approximately 611 MMcf per day at September 30, 2013.

Of the 151 operated horizontal wells on production at September 30, 2013,  82 were located in Bradford County, 8were located in Lycoming County and 61were located in Susquehanna County. Of the 80wells in progress at September 30, 2013,  38were either waiting on completion or waiting to be placed to sales, including 3in Bradford County, 8in Lycoming County and 27 in Susquehanna County.  A graph of the company’s gross operated production by county is shown below:

 

In the fourth quarter of 2013, the company expects to drill its first well in SullivanCounty on a portion of the undeveloped acreage it purchased in May of 2013. The company’s first wells in Wyoming and Tioga Counties are currently scheduled early in 2014.

- MORE -

Results from the company’s drilling activities from 2010 by quarter are shown below.

Time Frame	30th-Day Avg Rate (# of wells)	Average Completed Lateral Length	AverageRE-RE (Rig Days)	Average Completed Well Cost ($MM)
3rdQtr 2010	1,405 (1)	2,927	22.6	$5.8
4th Qtr 2010	5,584 (6)	3,805	19.8	$7.1
1st Qtr 2011	5,052 (3)	3,864	18.1	$6.6
2nd Qtr 2011	6,114 (7)	4,780	13.4	$6.7
4th Qtr 2011	5,284 (5)	4,129	18.8	$6.0
1st Qtr 2012	7,327 (2)	4,009	13.2	$6.0
2nd Qtr 2012	3,859 (17)	3,934	12.9	$6.0
3rd Qtr 2012	4,493 (8)	4,380	13.2	$5.7
4th Qtr 2012	4,606 (22)	3,830	15.9	$7.0
1st Qtr 2013	5,356 (21)	4,712	11.0	$7.0
2nd Qtr 2013	5,530 (37)	4,654	11.6	$6.6
3rd Qtr 2013	4,540 (15)	5,404	11.5	$7.3

- MORE -

The graph below provides normalized average daily production data through September 30, 2013, for the company’s horizontal wells in the Marcellus Shale. The “pink curve” indicates results for 32 wells with more than 18 fracture stimulation stages, the “purple curve” indicates results for 66wells with 13 to 18 fracture stimulation stages, the “orange curve” indicates results for 49wells with 9 to 12 fracture stimulation stages and the “green curve” indicates results for 4wells 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, 8,  12and 16Bcf typecurves are shown solely for reference purposes and are not intended to be projections of the performance of the company’s wells.

 

In October,  Southwestern secured additional firm transportation capacity, subject to completing a new interconnect project, beginning in November 2014 for up to an additional 150,000 MMBtu per day. This agreement increases the company’s total contracted firm transportation capacity for its Marcellus Shale gas to up to approximately 870MMcf per day by year-end 2014 and over 1 Bcf per day by year-end of 2015.

- MORE -

Fayetteville Shale – For the third quarter of 2013, Southwestern placed a total of 89 operated horizontal wells on production in the Fayetteville Shale. At September 30, 2013, the company’s gross operated production rate was approximately 2,030 MMcf per day.  

During the third quarter of 2013, the company’s horizontal wells had an average horizontal lateral length of 5,490 feet and average time to drill to total depth of 6.5 days from re-entry to re-entry for an average completed well cost of $2.6 million per well. This compares to an average horizontal lateral length of 5,165 feet and average time to drill to total depth of 6.2 days from re-entry to re-entryfor an average completed well cost of $2.3 million per well in the second quarter of 2013.  In the third quarter of 2013, the company had 33 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 385 wells drilled to total depth of 5 days or less from re-entry to re-entry.

In the third quarter of 2013, Southwestern placed on production its two highest-rate wells since the inception of the play. The company’s Sneed 08-12 6-1H7 well located in Faulkner County and the Ledbetter 07-16 12-14H well located in Conway County achieved peak 24-hour production rates of 10,084 and 9,148 Mcf per day, respectively. In the third quarter, Southwestern placed a total of 19 wells on line that achieved peak 24-hour production rates in excess of 6,000 Mcf per day. Additionally, in October, Southwestern has placed another 6 wells on line with peak 24-hour production rates above 6,000 Mcf per day, including 2 wells which are producing from the Upper Fayetteville formation. In total, the company’s wells placed on production during the third quarter of 2013 averaged initial production rates of 4,979 Mcf per day. Results from the company’s drilling activities from 2007 by quarter are shown below.

- MORE -

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
3rdQtr 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	2,816 (105)	2,447(105)	4,974
4th Qtr 2012	111	3,962	2,815 (111)	2,405 (111)	4,784
1st Qtr 2013	102	3,301	2,366  (102)	2,069  (102)	4,942
2nd Qtr 2013	126	3,625	2,233 (126)	1,980 (125)	5,165
3rd Qtr 2013	89	4,979	2,493 (61)	2,146 (31)	5,490

Note: Results as of September 30, 2013. 

(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.

- MORE -

Ark-La-Tex –Totalnet production from the company’s East Texas and conventional Arkoma Basin assets was 14.1 Bcfe in the first nine months of 2013, compared to 20.3 Bcfe in the first nine months of 2012.The decline in production is primarily due to the sale of a portion of the company’s East Texas properties in 2012.

New Ventures–In the Lower Smackover Brown Denseproject located in southern Arkansas and northern Louisiana, the company has drilled ten operated wells in the play area to date, fiveof which are currently testing or producing,  one is waiting on completion and one is drilling.  The most recent well placed on production was the company’s Sharp 22-22-1 #1 vertical well in Union Parish, Louisiana,which was drilled to a total vertical depth of 9,776 feet and was completed with 3 stages. The company is encouraged by initial flow rates from this well which achieved a peak 24-hour production rate of approximately 600barrelsof condensate and 1.3MMcf of 1,240-Btu gas per day.After 88 days, the well is currently producing approximately 530 barrels of oil and 1.1 million cubic feet of gas per day on a 16/64-inch choke.  The company’s Hollis 27-22-3 #1 vertical well in Union Parish was drilled to a total vertical depth of 11,429 feet and was completed with 3stages and has recently begun flowback.  Thecompany drilled theDean 31-22-2H Alt horizontal well in Union Parish in April to a total vertical depth of 10,055 feet with a lateral length of 3,172 feet. Additional testing in this wellis planned in the second quarter of 2014.  The company’s McMahen  19-21 #1-7 vertical well in Columbia County, Arkansas, was recently drilled to a total vertical depth of 11,365 feet and is expected to be completed with 3 to 4 stages in November.Southwestern has also spudanother vertical well, the Plum Creek 13-23-2 #1V,  in Union Parish, Louisiana in late-October.

In the Denver-Julesburg Basin in eastern Colorado,  the company’s Staner 5-58 #1-8 horizontal well located in Arapahoe County was completed with 14successful stages and began flowing back in late July. The well achieved a peak 24-hour production rate of 146 barrels of oil per day and 59 Mcf of gas per day. The company plans to continue to test the concept with additional wells in the area in the first quarter of 2014.

Explanation and Reconciliation of Non-GAAP Financial Measures

The company reportsits 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 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.

- MORE -

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 ninemonths ended September 30, 2013 and September 30, 2012. 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 September 30,
	2013	2012
	(in thousands)
Net income (loss):
Net income (loss)	$ 185,867	$ (54,053)
Deduct (add back):
Impairment of natural gas and oil properties (net of taxes)	--	(185,669)
Unrealized gain (loss) on derivative contracts (net of taxes)	6,059	(701)
Adjusted net income	$ 179,808	$ 132,317

	9 Months Ended September 30,
	2013	2012
	(in thousands)
Net income (loss):
Net income (loss)	$ 559,013	$ (351,481)
Deduct (add back):
Impairment of natural gas and oil properties (net of taxes)	--	(682,039)
Unrealized gain on derivative contracts (net of taxes)	43,562	558
Adjusted net income	$ 515,451	$ 330,000

	3 Months Ended September 30,
	2013	2012
Diluted earnings per share:
Net income (loss) per share	$ 0.53	$ (0.16)
Deduct (add back):
Impairment of natural gas and oil properties (net of taxes)	--	(0.53)
Unrealized gain (loss) on derivative contracts (net of taxes)	0.02	(0.01)
Adjusted net income per share	$ 0.51	$ 0.38

	9 Months Ended September 30,
	2013	2012
Diluted earnings per share:
Net income (loss) per share	$ 1.59	$ (1.01)
Deduct (add back):
Impairment of natural gas and oil properties (net of taxes)	--	(1.96)
Unrealized gain on derivative contracts (net of taxes)	0.12	--
Adjusted net income per share	$ 1.47	$ 0.95

- MORE -

	3 Months Ended September 30,
	2013	2012
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 499,966	$ 355,087
Deduct (add back):
Change in operating assets and liabilities	(26,691)	(61,523)
Net cash provided by operating activities before changes  in operating assets and liabilities	$ 526,657	$ 416,610

	9 Months Ended September 30,
	2013	2012
	(in thousands)
Cash flow from operating activities:
Net cash provided by operating activities	$ 1,377,518	$ 1,192,477
Deduct (add back):
Change in operating assets and liabilities	(68,028)	50,520
Net cash provided by operating activities before changes  in operating assets and liabilities	$ 1,445,546	$ 1,141,957

	3 Months Ended September 30,
	2013	2012
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$ 222,692	$ (141,865)
Deduct (add back):
Impairment of natural gas and oil properties	--	(289,821)
E&P segment operating income excluding impairment  of natural gas and oil properties	$ 222,692	$ 147,956

	9 Months Ended September 30,
	2013	2012
	(in thousands)
E&P segment operating income:
E&P segment operating income (loss)	$ 650,996	$ (745,533)
Deduct (add back):
Impairment of natural gas and oil properties	--	(1,090,473)
E&P segment operating income excluding impairment  of natural gas and oil properties	$ 650,996	$ 344,940

- MORE -

Southwestern management will host a teleconference call on Friday,  November 1,  2013 at 10:00 a.m. EST to discuss itsthird quarter 2013 results. The toll-free number to call is 877-407-8035and the international dial-in 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 mayoccur in the future, including, without limitation, statements regarding the financial position, business strategy, productionand 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 orrevise 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 unknownrisks, 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 orachievements expressed or implied by the forward-looking statements. In addition to any assumptions and other factorsreferred 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 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 counterpartiesandany 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,	2013		2012		2013		2012
Exploration & Production
Production
Gas Production ( Bcf)		172.1		144.2		479.4		414.7
Oil Production (MBbls)		37		19		102		59
NGL production (MBbls)		12		–		40		–
Total equivalent production (Bcfe)		172.4		144.3		480.3		415.1
Commodity Prices
Average realized gas price per Mcf, including hedges	$	3.60	$	3.41	$	3.63	$	3.33
Average realized gas price per Mcf, excluding hedges	$	3.06	$	2.35	$	3.18	$	2.12
Average oil price per Bbl	$	106.72	$	99.67	$	105.05	$	102.89
Average NGL price per Bbl	$	42.05	$	–	$	44.20	$	–
Operating Expenses per Mcfe
Lease operating expenses	$	0.87	$	0.79	$	0.85	$	0.80
General & administrative expenses	$	0.24	$	0.21	$	0.23	$	0.26
Taxes, other than income taxes	$	0.09	$	0.09	$	0.10	$	0.10
Full cost pool amortization	$	1.07	$	1.30	$	1.07	$	1.34
Midstream
Gas volumes marketed (Bcf)		206.4		171.2		574.9		498.7
Gas volumes gathered (Bcf)		229.9		214.7		667.3		622.9

STATEMENTS OF OPERATIONS (Unaudited)					Page 2 of 5
Southwestern Energy Company and Subsidiaries
	Three Months				Nine Months
Periods Ended September 30,	2013		2012		2013		2012
		(in thousands, except share/per amounts)
Operating Revenues
Gas sales	$	617,427	$	497,219	$	1,736,101	$	1,394,745
Gas marketing		201,112		148,764		581,932		423,503
Oil sales		4,397		1,889		12,431		6,097
Gas gathering		45,430		43,855		133,592		128,293
		868,366		691,727		2,464,056		1,952,638
Operating Costs and Expenses
Gas purchases - midstream services		195,271		149,651		575,337		423,941
Operating expenses		90,269		61,906		236,648		179,478
General and administrative expenses		50,969		36,121		135,754		129,879
Depreciation, depletion and amortization		204,934		203,935		571,268		605,392
Impairment of natural gas and oil properties		–		289,821		–		1,090,473
Taxes, other than income taxes		17,694		16,252		58,543		51,154
		559,137		757,686		1,577,550		2,480,317
Operating Income (Loss)		309,229		(65,959)		886,506		(527,679)
Interest Expense
Interest on debt		25,435		25,463		74,581		69,154
Other interest charges		1,049		1,058		3,203		3,096
Interest capitalized		(15,466)		(15,915)		(48,467)		(45,945)
		11,018		10,606		29,317		26,305
Other Gain (Loss), Net		(319)		238		(498)		2,615
Gain (Loss) on Derivatives		12,124		(5,879)		75,779		(10,593)
Income (Loss) Before Income Taxes		310,016		(82,206)		932,470		(561,962)
Provision for Income Taxes
Current		(16,068)		101		402		369
Deferred		140,217		(28,254)		373,055		(210,850)
		124,149		(28,153)		373,457		(210,481)
Net Income (Loss)	$	185,867	$	(54,053)	$	559,013	$	(351,481)
Earnings (Loss) Per Share
Basic	$	0.53	$	(0.16)	$	1.60	$	(1.01)
Diluted	$	0.53	$	(0.16)	$	1.59	$	(1.01)
Weighted Average Common Shares Outstanding
Basic		350,517,337		348,649,630		350,334,634		348,272,192
Diluted		351,222,830		348,649,630		351,014,974		348,272,192

BALANCE SHEETS (Unaudited)		Page 3 of 5
Southwestern Energy Company and Subsidiaries
September 30,		2013		2012
	(in thousands)
ASSETS
Current Assets		$	739,975	$	846,747
Property and Equipment			14,823,553		12,506,903
Less: Accumulated depreciation, depletion and amortization			(7,786,820)		(6,131,344)
			7,036,733		6,375,559
Other Long-Term Assets			117,680		134,256
			7,894,388		7,356,562
LIABILITIES AND EQUITY
Current Liabilities			809,811		761,165
Long-Term Debt			1,911,165		1,695,342
Deferred Income Taxes			1,388,833		1,313,584
Other Long-Term Liabilities			264,590		159,462
Commitments and Contingencies
Equity
Common stock, $0.01 par value; authorized 1,250,000,000 shares; issued 351,768,352 shares in 2013 and 351,415,917 in 2012			3,517		3,504
Additional paid-in capital			960,058		928,322
Retained earnings			2,508,163		2,304,733
Accumulated other comprehensive income			48,758		192,040
Common stock in treasury; 14,625 shares in 2013 and 66,791 in 2012			(507)		(1,590)
Total Equity			3,519,989		3,427,009
		$	7,894,388	$	7,356,562

STATEMENTS OF CASH FLOWS (Unaudited)		Page 4 of 5
Southwestern Energy Company and Subsidiaries
		Nine Months
Periods Ended September 30,		2013		2012
	(in thousands)
Cash Flows From Operating Activities
Net Income (loss)		$	559,013	$	(351,481)
Adjustment to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization			574,221		608,167
Impairment of natural gas and oil properties			–		1,090,473
Deferred income taxes			373,055		(210,850)
Mark to market gain on derivatives			(72,664)		(892)
Stock-based compensation			8,883		8,226
Other			3,038		(1,686)
Change in assets and liabilities			(68,028)		50,520
Net cash provided by operating activities			1,377,518		1,192,477
Cash Flows From Investing Activities
Capital investments			(1,727,543)		(1,623,751)
Proceeds from sale of property and equipment			3,081		201,161
Transfers to restricted cash			–		(167,774)
Transfers from restricted cash			8,542		40,700
Other			4,700		5,239
Net cash used in investing activities			(1,711,220)		(1,544,425)
Cash Flows From Financing Activities
Payments on current portions of long-term debt			(600)		(600)
Payments on revolving long-term debt			(2,134,550)		(1,774,000)
Borrowings under revolving long-term debt			2,377,950		1,129,000
Change in bank drafts outstanding			49,106		1,627
Proceeds from issuance of long term debt			–		998,780
Debt Issuance costs			–		(8,338)
Proceeds from exercise of common stock options			6,751		8,422
Net cash provided by financing activities			298,657		354,891
Effect of exchange rate changes on cash			412		(10)
Increase (decrease) in cash and cash equivalents			(34,633)		2,933
Cash and cash equivalents at beginning of year			53,583		15,627
Cash and cash equivalents at end of period		$	18,950	$	18,560

SEGMENT INFORMATION (Unaudited)								Page 5 of 5
Southwestern Energy Company and Subsidiaries		Exploration
		and		Midstream
		Production		Services		Other			Eliminations		Total
	(in thousands)
Quarter Ending September 30, 2013
Revenues		$	622,477	$	847,605	$	96		$	(601,812)	$	868,366
Gas purchases			–		701,304		–			(506,033)		195,271
Operating expenses			150,602		35,395		30			(95,758)		90,269
General & administrative expenses			42,013		8,937		40			(21)		50,969
Depreciation, depletion & amortization			191,860		12,970		104			–		204,934
Taxes, other than income taxes			15,310		2,341		43			–		17,694
Operating income			222,692		86,658		(121)			–		309,229
Capital investments(1)			496,331		40,052		5,726			–		542,109
Quarter Ending September 30, 2012
Revenues		$	498,101	$	602,339	$	849		$	(409,562)	$	691,727
Gas purchases			–		474,628		–			(324,977)		149,651
Operating expenses			113,416		32,221		56			(83,787)		61,906
General & administrative expenses			30,256		6,615		48			(798)		36,121
Depreciation, depletion & amortization			192,994		10,620		321			–		203,935
Impairment of natural gas and oil properties			289,821		–		–			–		289,821
Taxes, other than income taxes			13,479		2,767		6			–		16,252
Operating income (loss)			(141,865)		75,488		418			–		(65,959)
Capital investments(1)			385,585		31,693		7,608			–		424,886
Nine months Ending September 30, 2013
Revenues		$	1,752,638	$	2,455,287	$	257		$	(1,744,126)	$	2,464,056
Gas purchases			–		2,042,948		–			(1,467,611)		575,337
Operating expenses			406,586		106,415		104			(276,457)		236,648
General & administrative expenses			111,605		24,120		87			(58)		135,754
Depreciation, depletion & amortization			533,577		37,377		314			–		571,268
Taxes, other than income taxes			49,874		8,573		96			–		58,543
Operating income			650,996		235,854		(344)			–		886,506
Capital investments(1)			1,602,885		135,425		16,748			–		1,755,058
Nine months Ending September 30, 2012
Revenues		$	1,399,033	$	1,637,188	$	2,552		$	(1,086,135)	$	1,952,638
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			571,935		32,499		958			–		605,392
Impairment of natural gas and oil properties			1,090,473		–		–			–		1,090,473
Taxes, other than income taxes			41,966		9,194		(6)			–		51,154
Operating income (loss)			(745,533)		216,598		1,256			–		(527,679)
Capital investments(1)			1,450,569		105,576		30,486			–		1,586,631
(1) Capital investments includes decreases of $14.6 million and $56.2 million for the three-month periods ended September 30, 2013 and 2012, respectively, and increases of $25.8 million and a decrease of $40.7 million for the nine-month periods ended September 30, 2013 and 2012, respectively, relating to the change in accrued expenditures between periods.