NEWS RELEASE –

SOUTHWESTERN ENERGY ANNOUNCES 2016 THIRD QUARTER

OPERATIONAL UPDATE AND FINANCIAL RESULTS

Houston, Texas – October 20, 2016...Southwestern Energy Company (NYSE: SWN) today announced its financial and operating results for the quarter ended September 30, 2016.

“During the third quarter, we once again delivered on our commitments and delivered solid results through our relentless focus on value creation in the current pricing environment,” remarked Bill Way, President and Chief Executive Officer of Southwestern Energy.  “As operations ramp up, we are also enhancing our laser focus on growing margins, evidenced this quarter by a reduction of lease operating expenses per unit for the fifth consecutive quarter.  As we look forward to 2017, our capital rigor and commitment to balance sheet strength will remain central to delivering value-adding growth from our vast portfolio.”

Highlights for the third quarter include:

· Outstanding reinitiation of drilling and completion activities within each of the Company’s core assets, highlighted by our ability to utilize our company-owned rig fleet to ramp activity quickly and resume our pacesetter results:

o Three-well pad placed to sales in Northeast Appalachia with a cumulative initial production rate exceeding 50 MMcf per day;

o Improved drilling performance in each operating area, surpassing levels achieved in late 2015 prior to pause in activity;

o Fayetteville wells placed to sales in the third quarter averaging 6,701 Mcf per day;

· Total net production of 211 Bcfe, including 121 Bcfe from the Appalachian Basin and 90 Bcf from the Fayetteville Shale, largely due to impressive well performance and continuing optimization of gathering systems in all of our areas;

· Net cash provided by operating activities of $172 million and net cash flow (a non-GAAP measure reconciled below) of $173 million;

· Net loss attributable to common stock of $735 million, or $1.52 per diluted share, and adjusted net income attributable to common stock (a non-GAAP measure reconciled below) of $12 million, or $0.03 per diluted share;

· Completion of announced balance sheet strengthening initiatives resulting in a decrease in total debt and net debt (a non-GAAP measure reconciled below) of $1.1 billion and $1.6 billion, respectively, since June 30; and

· Continued progress on our hedging strategy; 535 Bcf of 2017 net gas production hedged utilizing fixed price swaps and collars with an average swap or purchased put strike price of $3.00 per Mcf.

Third Quarter of 2016 Financial Results

For the third quarter of 2016, Southwestern reported a net loss attributable to common stock of $735 million, or $1.52 per diluted share, and adjusted net income attributable to common stock (a non-GAAP measure) of $12 million, or $0.03 per diluted share.  This compares to a net loss attributable to common stock of $1.8 billion, or $4.62 per diluted share, and an adjusted net income attributable to common stock of $3 million, or $0.01 per diluted share, in the third quarter of 2015.

Net cash provided by operating activities was $172 million for the third quarter of 2016, compared to $287 million in the third quarter of 2015.  Net cash flow (a non-GAAP measure) was $173 million for the third quarter of 2016, compared to $330 million for the same period in 2015.

E&P Segment – The operating loss from the Company’s E&P segment was $777 million for the third quarter of 2016, compared to an operating loss of $2.9 billion during the third quarter of 2015.  The decreased operating loss was primarily due to a smaller non-cash impairment in 2016. Adjusted operating income from the Company’s E&P segment was $42 million for the third quarter of 2016 (a non-GAAP measure), compared to an adjusted operating loss of $71 million for the same period in 2015. The increase in adjusted operating income was primarily due to lower operating costs and higher realized NGL prices partially offset by decreased realized natural gas prices and decreased production.

Net production totaled 211 Bcfe in the third quarter of 2016, down from 249 Bcfe in the third quarter of 2015 as a result of limited drilling and completion activity.  The quarter included 90 Bcf from the Fayetteville Shale, 84 Bcf from Northeast Appalachia and 37 Bcfe from Southwest Appalachia.  This compares to 118 Bcf from the Fayetteville Shale, 93 Bcf from Northeast Appalachia and 37 Bcfe from Southwest Appalachia in the third quarter of 2015.

Due to the continued challenging commodity price environment, Southwestern’s average realized gas price including the effect of derivatives in the third quarter of 2016 was $1.73 per Mcf, down from $2.21 per Mcf in the third quarter of 2015. The Company’s commodity derivative activities decreased its average realized gas price by $0.05 per Mcf during the third quarter of 2016, compared to an increase of $0.44 per Mcf during the same period in 2015. As of October 18, 2016, the Company had approximately 99 Bcf of its remaining 2016 forecasted gas production protected at an average swap or purchased put strike

price of $2.84 per Mcf with upside exposure on approximately 50% of those protected volumes.  Additionally, the Company had approximately 535 Bcf of its 2017 forecasted gas production protected at an average swap or purchased put strike price of $3.00 per Mcf with upside exposure on approximately 45%, or 239 Bcf, of those protected volumes to $3.33 per Mcf.  The Company also had approximately 160 Bcf of its 2018 forecasted gas production protected at an average swap or purchased put strike price of $2.94 per Mcf, with upside exposure on approximately 89%, or 141 Bcf, of those protected volumes to $3.35 per Mcf.

A detailed breakdown of the Company’s natural gas derivative financial instruments as of October 18, 2016 is shown below:

		Weighted Average Price per MMBtu
	Volume (Bcf)	Swaps		Sold Puts		Purchased Puts		Sold Calls
Financial protection on production
2016
Fixed price swaps	51	$	2.81	$	–	$	–	$	–
Purchased put options	4	$	–	$	–	$	2.34	$	–
Two-way costless-collars	40	$	–	$	–	$	2.93	$	3.33
Three-way costless-collars	5	$	–	$	2.30	$	3.00	$	3.25
Total	99
2017
Fixed price swaps	296	$	3.04	$	–	$	–	$	–
Two-way costless-collars	103	$	–	$	–	$	2.94	$	3.38
Three-way costless-collars	135	$	–	$	2.29	$	2.97	$	3.30
Total	535
2018
Fixed price swaps	18	$	3.00	$	–	$	–	$	–
Two-way costless-collars	14	$	–	$	–	$	3.00	$	3.46
Three-way costless-collars	128	$	–	$	2.31	$	2.93	$	3.33
Total	160
Sold call options
2016	30	$	–	$	–	$	–	$	5.00
2017	86	$	–	$	–	$	–	$	3.25
2018	63	$	–	$	–	$	–	$	3.50
2019	52	$	–	$	–	$	–	$	3.50
2020	32	$	–	$	–	$	–	$	3.75
Total	263

Note: Amounts may not sum due to rounding

Like most producers, 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 derivatives, the Company’s average price received for its gas production during the third quarter of 2016 was approximately $1.03 per Mcf lower than average NYMEX settlement prices, compared to approximately $1.00 per Mcf lower than average NYMEX settlement prices during the third quarter of 2015. 

As is historically the case, the Company experiences its widest differentials in the third quarter.  This widening basis for the third quarter of 2016 was influenced largely by regional storage levels being at or near capacity.  Factoring in the forecasted gains of approximately $0.03 per Mcf on basis hedges currently in place, the Company anticipates its total company basis differential to end the year at the high end of its guidance, which is $0.83 per Mcf. Based on current expectations, these gains for 2016 are expected to total over $20 million and will be reported as part of hedge gains.

The Company’s basis hedging program includes protection associated with physical sales agreements that is reported as a component of realized gas price excluding derivatives and; therefore, is included in the gas basis differential and transportation charge guidance.  This program also includes financial instruments with the results of which are reported as realized gas price including derivatives and are not included in guidance. 

As of September 30, 2016, the Company mitigated the volatility of basis differentials by protecting basis on approximately 75 Bcf of the remaining 2016 expected natural gas production through financial derivative instruments and physical sales arrangements at a basis differential to NYMEX natural gas prices of approximately ($0.08) per Mcf. Additionally, the Company has protected basis on approximately 196 Bcf of its 2017 forecasted natural gas production at a basis differential to NYMEX natural gas prices of approximately ($0.33) per Mcf.  Please refer to our quarterly report on Form 10-Q filed with the Securities and Exchange Commission, for additional information on the Company’s commodity, basis and interest rate protection.

Lease operating expenses per unit of production for the Company’s E&P segment were down to $0.86 per Mcfe in the third quarter of 2016, compared to $0.92 per Mcfe in the third quarter of 2015. The decrease was primarily due to the successful renegotiation of the existing gathering and processing rates in Southwest Appalachia.

General and administrative expenses per unit of production were $0.23 per Mcfe in the third quarter of 2016, compared to $0.20 per Mcfe in the third quarter of 2015. This increase was primarily due to the decreased volumes in 2016.  This excludes the restructuring charges associated with the workforce reduction, which were $2 million for the E&P segment in the third quarter of 2016.

Taxes other than income taxes were flat at $0.10 per Mcfe in the third quarter of 2016 as compared to the third quarter of 2015. 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 declined significantly to $0.35 per Mcfe in the third quarter of 2016, compared to $0.98 per Mcfe in the third quarter of 2015. The amortization rate is impacted by the timing and amount of reserve additions, 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 impairments, 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, including but not limited to the uncertainty of the amount of future reserve changes.

Midstream – Operating income for the Company’s Midstream segment, comprised of gathering and marketing activities, was $52 million for the third quarter of 2016, compared to $68 million for the same period in 2015.  Adjusted operating income (a non-GAAP measure) for the Company’s Midstream segment was $52 million for the third quarter of 2016, compared to $69 million for the same period in 2015. The decrease in operating income was largely due to a decrease in volumes gathered, resulting from lower production volumes in the Fayetteville Shale.

First Nine Months of 2016 Financial Results

For the first nine months of 2016, Southwestern reported a net loss attributable to common stock of $2.5 billion, or $6.02 per diluted share, and an adjusted net loss attributable to common stock (a non-GAAP measure) of $52 million, or $0.12 per diluted share.  This compares to a net loss attributable to common stock of $2.5 billion, or $6.65 per diluted share, and an adjusted net income attributable to common stock of $77 million, or $0.20 per diluted share, in the first nine months of 2015.   

Net cash provided by operating activities was $337 million for the first nine months of 2016, compared to $1.2 billion in the first nine months of 2015.  Net cash flow (a non-GAAP measure) was $434 million for the first nine months of 2016, compared to $1.2 billion for the same period in 2015.

E&P Segment – The operating loss from the Company’s E&P segment was $2.5 billion for the first nine months of 2016, compared to an operating loss of $4.5 billion during the first nine months of 2015. The decreased operating loss was primarily due to a smaller non-cash impairment in 2016. Adjusted operating loss from the Company’s E&P segment was $91 million for the first nine months of 2016 (a non-GAAP measure), compared to an adjusted operating loss of $97 million for the same period in 2015. The improvement in adjusted operating loss was primarily due to lower operating costs partially offset by lower realized natural gas prices and decreased production.

Net production totaled 673 Bcfe in the first nine months of 2016, down from 727 Bcfe in the first nine months of 2015.  The first nine months of 2016 included 289 Bcf from the Fayetteville Shale, 268 Bcf from Northeast Appalachia and 115 Bcfe from Southwest Appalachia.  This compares to 354 Bcf from the Fayetteville Shale, 263 Bcf from Northeast Appalachia and 103 Bcfe from Southwest Appalachia in the first nine months of 2015.

Due to the continued challenging commodity price environment, in the first nine months of 2016, Southwestern’s average realized gas price including the effect of derivatives was $1.51 per Mcf, down from $2.47 per Mcf in the first nine months of 2015. The Company’s

commodity derivative activities increased its average realized gas price by $0.04 per Mcf during the first nine months of 2016, compared to an increase of $0.42 per Mcf during the same period in 2015. Disregarding the impact of derivatives, the Company’s average price received for its gas production during the first nine months of 2016 was approximately $0.82 per Mcf lower than average NYMEX settlement prices, compared to approximately $0.75 per Mcf lower than average NYMEX settlement prices during the first nine months of 2015.

Lease operating expenses per unit of production for the Company’s E&P segment declined to $0.87 per Mcfe in the first nine months of 2016, compared to $0.92 per Mcfe in the first nine months of 2015. The decrease was primarily due to reduced workover activity and contract services as well as the successful renegotiation of the existing gathering and processing rates in Southwest Appalachia.

General and administrative expenses per unit of production decreased to $0.21 per Mcfe in the first nine months of 2016, compared to $0.22 per Mcfe in the first nine months quarter of 2015. The lower employee costs in 2016 more than offset the impact of declining production volumes. This excludes the restructuring charges associated with the workforce reduction, which were $71 million for the E&P segment in the first nine months of 2016.

Taxes other than income taxes were down to $0.09 per Mcfe in the first nine months of 2016, compared to $0.11 per Mcfe in the first nine months of 2015. This excludes the restructuring charges associated with the workforce reduction, which were $3 million for the E&P segment in the first nine months of 2016.

The Company’s full cost pool amortization rate declined significantly to $0.40 per Mcfe in the first nine months of 2016, compared to $1.08 per Mcfe in the first nine months of 2015.

Midstream – Operating income for the Company’s Midstream segment was $169 million for the first nine months of 2016, compared to $511 million for the same period in 2015. The decrease in operating income was primarily due to 2015 including a $277 million gain on sale of assets divested. Adjusted operating income (a non-GAAP measure) for the Company’s Midstream segment was $172 million for the first nine months of 2016, excluding the impacts from restructuring charges, compared to $234 million for the same period in 2015, which excluded a $277 million gain on sale of assets divested. The decrease in adjusted operating income was largely due to a decrease in volumes gathered resulting from lower production volumes in the Fayetteville Shale and the sale of the Company’s northeast Pennsylvania gathering assets.

Capital Structure and Investments –  At September 30, 2016, the Company had total debt of approximately $4.7 billion and $3.2 billion in net debt (a non-GAAP measure).

As of September 30, 2016, there were no borrowings under the Company’s revolving credit facilities; however, $174 million in letters of credit was outstanding under the new revolving credit facility.  As a result of the equity offering closed in July 2016, the Company

repaid $375 million of its $750 million term loan originally due in November 2018, which extended the maturity on this term loan to December 2020, subject to certain conditions.  The Company paid down an additional $48 million following the closing of the previously announced sale of approximately 55,000 net acres in West Virginia.  At September 30, 2016, the Company has $317 million in remaining 2017 and 2018 debt maturities, well below the $1.0 billion at December 31, 2015 and also well below the $1.5 billion cash balance.

During the first nine months of 2016, Southwestern invested a total of $376 million.  This is down from $2.1 billion in the first nine months of 2015. The $376 million includes approximately $372 million invested in its E&P business, $3 million invested in its Midstream segment and $1 million invested for corporate and other purposes.  Of the $376 million, approximately $123 million was associated with capitalized interest and $62 million was associated with capitalized expenses.

E&P Operations Review

During the first nine months of 2016, Southwestern invested approximately $372 million in its E&P business, including $189 million in investment capital and $183 in capitalized interest and expenses. 

In Northeast Appalachia, the Company had net gas production of 84 Bcf in the third quarter of 2016, compared to 93 Bcf in the third quarter of 2015.  In the third quarter of 2016, it invested $52 million, drilling 18 wells, completing 9 wells and placing 3 wells on production.  Gross operated production in Northeast Appalachia was approximately 1,046 MMcf per day at September 30, 2016.  The Company plans to place 21 wells on production in the fourth quarter of 2016.

During the third quarter, Northeast Appalachia drilled 18 wells utilizing advanced techniques, such as the use of rotary steerable tools, that resulted in an average drill to total depth of less than 8 days from re-entry to re-entry which is 5 percent faster than when the Company paused operations at the end of 2015.  Included in these results was a well that drilled over 4,700 feet in 24 hours, a record for the Company in Northeast Appalachia.  A number of the nine horizontal wells completed used a new completion design based on higher intensity stimulation. This, when coupled with optimized flow techniques, showed very encouraging early results.  For example, the Racine pad, located in Susquehanna County, came online at greater than 50 million cubic feet per day from 3 wells, materially better than the previous offset wells.

In Southwest Appalachia, the Company invested $41 million during the third quarter of 2016, drilling 4 wells and completing 8 wells, the first of which is expected to be placed to sales in the fourth quarter of 2016. Net production was flat at 37 Bcfe in the third quarter of 2016 as compared to the third quarter of 2015.  The gross operated production rate in Southwest Appalachia was approximately 621 MMcfe per day at September 30, 2016.  Southwestern plans to place 9 wells on production in the fourth quarter of 2016. 

The Company continues to focus on margin improvements and has reduced its lease operating expenses in Southwest Appalachia to $1.06 per Mcfe in the first nine months of 2016, compared to $1.39 per Mcfe in the first nine months of 2015. The reduction is a result of the successful renegotiation of its gathering and processing rates as well as operating efficiencies implemented throughout the year.

In the third quarter, Southwest Appalachia continued to realize efficiencies in its drilling and completions operations.  Throughout the restart of activity, re-entry to re-entry days decreased and stages completed per day increased compared to the fourth quarter of 2015. Additionally, the Company continued to test tighter stage spacing, leveraging its learnings from previous tests such as the continued outperformance of the Alice Edge pad, which was brought online in the fourth quarter of 2015.  Tighter stage spaced wells are continuing to perform materially better on an estimated ultimate recovery per foot basis than offset wells.   

The Company achieved a monumental milestone in the Fayetteville Shale during the third quarter of 2016, surpassing 5 Tcf of cumulative production since its inception.  After over a decade of development, this asset continues to account for approximately two percent of the nation’s natural gas supply and remains a significant value creator for the Company. 

In the Fayetteville Shale, Southwestern invested $17 million, drilling 1 well, completing 8 wells and placing 6 wells to sales in the third quarter of 2016. Net gas production was 90 Bcf in the third quarter of 2016, compared to 118 Bcf in the third quarter of 2015. Gross operated gas production in the Fayetteville Shale was approximately 1,443 MMcf per day at September 30, 2016.  The company plans to place 22 wells on production in the fourth quarter of 2016.

The 6 wells in this operating area placed on production in the third quarter had an average initial production rate of 6,701 Mcf per day. Similar to the other operating areas, the Company is currently testing increased proppant volumes which are over two times greater than historical well completions in the Fayetteville Shale.  Additionally, Southwestern is continuing testing of its concept surrounding the Moorefield Shale as it progresses its efforts to lower the breakeven prices in the Fayetteville operating area.

Company-wide as of September 30, Southwestern had 101 wells that were either waiting on completion or waiting to be placed to sales, including 37 in Northeast Appalachia, 36 in Southwest Appalachia and 28 in Fayetteville.  The Company expects to exit 2016 with approximately 85 drilled but uncompleted wells, returning to a normal maintenance level for efficient operations of approximately 60 by early 2017.

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 financial statement

users with additional meaningful comparisons between current results, the results of its peers and of prior periods. 

One such non-GAAP financial measure is net cash flow. 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.

Additional non-GAAP financial measures the Company may present from time to time are net debt, adjusted net income, adjusted diluted earnings per share, adjusted EBITDA and its E&P and Midstream 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 position and performance are measured relative to the position and 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 throughout this release of GAAP financial measures to non-GAAP financial measures as of and for the three and nine months ended September 30, 2016 and September 30, 2015, as applicable. 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,
	2016		2015
	(in millions)
Net income (loss) attributable to common stock:
Net loss attributable to common stock	$	(735)	$	(1,766)
Add back:
Participating securities - mandatory convertible preferred stock		(2)		(0)
Impairment of natural gas and oil properties		817		2,839
Restructuring charges		2		1
Loss on sale of assets, net		–		1
Loss on early extinguishment of debt and other(1)		57		–
Transaction costs		–		1
(Gain) loss on certain derivatives		(81)		34
Adjustments due to inventory valuation		(1)		–
Adjustments due to discrete tax items (2)		256		–
Tax impact on adjustments		(301)		(1,107)
Adjusted net income attributable to common stock	$	12	$	3

(1) Includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt which were included in other interest charges.

(2) 2016 primarily relates to the exclusion of certain discrete tax adjustments in the third quarter of 2016 due to an increase to the valuation allowance against the Company’s deferred tax assets.  The Company expects its 2016 income tax rate to be 38.0% before the impacts of any valuation allowance.

	3 Months Ended Sept 30,
	2016		2015
Diluted earnings per share:
Diluted earnings per share	$	(1.52)	$	(4.62)
Add back:
Participating securities - mandatory convertible preferred stock		(0.00)		(0.00)
Impairment of natural gas and oil properties		1.69		7.43
Restructuring charges		0.01		0.00
Loss on sale of assets, net		–		0.00
Loss on early extinguishment of debt and other(1)		0.12		–
Transaction costs		–		0.00
(Gain) loss on certain derivatives		(0.17)		0.09
Adjustments due to inventory valuation		(0.00)		–
Adjustments due to discrete tax items(2)		0.53		–
Tax impact on adjustments		(0.63)		(2.89)
Adjusted diluted earnings per share	$	0.03	$	0.01

(1) Includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt which were included in other interest charges.

(2) 2016 primarily relates to the exclusion of certain discrete tax adjustments in the third quarter of 2016 due to an increase to the valuation allowance against the Company’s deferred tax assets.  The Company expects its 2016 income tax rate to be 38.0% before the impacts of any valuation allowance.

	9 Months Ended Sept 30,
	2016		2015
	(in millions)
Net income (loss) attributable to common stock:
Net loss attributable to common stock	$	(2,514)	$	(2528)
Add back:
Participating securities – mandatory convertible preferred stock		–		(14)
Impairment of natural gas and oil properties		2,321		4,374
Restructuring charges		77		1
Gain on sale of assets, net		(2)		(276)
Loss on early extinguishment of debt and other(1)		57		–
Transaction costs		–		53
Loss on certain derivatives		48		105
Adjustments due to inventory valuation		3		–
Adjustments due to discrete tax items (2)		903		–
Tax impact on adjustments		(945)		(1,638)
Adjusted net income (loss) attributable to common stock	$	(52)	$	77

(1) Includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt which were included in other interest charges.

(2) 2016 primarily relates to the exclusion of certain discrete tax adjustments in the third quarter of 2016 due to an increase to the valuation allowance against the Company’s deferred tax assets.  The Company expects its 2016 income tax rate to be 38.0% before the impacts of any valuation allowance.

	9  Months Ended Sept 30,
	2016		2015
Diluted earnings per share:
Diluted earnings per share	$	(6.02)	$	(6.65)
Add back:
Participating securities – mandatory convertible preferred stock		–		(0.04)
Impairment of natural gas and oil properties		5.56		11.51
Restructuring charges		0.19		0.00
Gain on sale of assets, net		(0.01)		(0.73)
Loss on early extinguishment of debt and other(1)		0.14		–
Transaction costs		–		0.14
Loss on certain derivatives		0.12		0.28
Adjustments due to inventory valuation		0.01		–
Adjustments due to discrete tax items (2)		2.16		–
Tax impact on adjustments		(2.27)		(4.31)
Adjusted diluted earnings per share	$	(0.12)	$	0.20

(1) Includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt which were included in other interest charges.

(2) 2016 primarily relates to the exclusion of certain discrete tax adjustments in the third quarter of 2016 due to an increase to the valuation allowance against the Company’s deferred tax assets.  The Company expects its 2016 income tax rate to be 38.0% before the impacts of any valuation allowance.

	3 Months Ended Sept 30,
	2016		2015
	(in millions)
Cash flow from operating activities:
Net cash provided by operating activities	$	172	$	287
Add back:
Changes in operating assets and liabilities		–		43
Restructuring charges		1		–
Net Cash Flow	$	173	$	330
	9 Months Ended Sept 30,
	2016		2015
	(in millions)
Cash flow from operating activities:
Net cash provided by operating activities	$	337	$	1,227
Add back:
Changes in operating assets and liabilities		50		(65)
Restructuring charges		47		–
Net Cash Flow	$	434	$	1,162
	3 Months Ended Sept 30,
	2016		2015
	(in millions)
E&P segment operating income (loss):
E&P segment operating loss	$	(777)	$	(2,910)
Add back:
Impairment of natural gas and oil properties		817		2,839
Restructuring charges		2		–
Adjusted E&P segment operating income (loss)	$	42	$	(71)
	9 Months Ended Sept 30,
	2016		2015
	(in millions)
E&P segment operating income (loss):
E&P segment operating loss	$	(2,486)	$	(4,471)
Add back:
Impairment of natural gas and oil properties		2,321		4,374
Restructuring charges		74		–
Adjusted E&P segment operating loss	$	(91)	$	(97)

	3 Months Ended Sept 30,
	2016		2015
	(in millions)
Midstream segment operating income:
Midstream segment operating income	$	52	$	68
Add back:
Loss on sale of assets, net		–		1
Adjusted Midstream segment operating income	$	52	$	69
	9 Months Ended Sept 30,
	2016		2015
	(in millions)
Midstream segment operating income:
Midstream segment operating income	$	169	$	511
Add back:
Restructuring charges		3		–
Gain on sale of assets, net		–		(277)
Adjusted Midstream segment operating income	$	172	$	234

	September 30,		June 30,
	2016		2016
	(in millions)
Net debt:
Total debt	$	4,652	$	5,768
Subtract:
Cash and cash equivalents		(1,474)		(998)
Net debt	$	3,178	$	4,770

Southwestern management will host a teleconference call on Friday, October 21, 2016 at 10:00 a.m. Eastern to discuss its third quarter 2016 results. The toll-free number to call is 877-407-8035 and 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 natural gas and oil exploration, development and production, natural gas gathering and marketing. Additional information on the Company can be found on the Internet at http://www.swn.com.

Contact:

Michael Hancock

Director, Investor Relations

(832) 796-7367

michael_hancock@swn.com

This news release contains forward-looking statements. Forward-looking statements relate to future events and anticipated results of operations, business strategies, and other aspects of our operations or operating results. In many cases you can identify forward-looking statements by terminology such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “target” or similar words. Statements may be forward looking even in the absence of these particular words. Where, in any forward-looking statement, the Company expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that such expectation or belief will result or be achieved. The actual results of operations can and will be affected by a variety of risks and other matters including, but not limited to, changes in commodity prices; changes in expected levels of natural gas and oil reserves or production; operating hazards, drilling risks, unsuccessful exploratory activities; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; international monetary conditions; unexpected cost increases; potential liability for remedial actions under existing or future environmental regulations; potential liability resulting from pending or future litigation; and general domestic and international economic and political conditions; as well as changes in tax, environmental and other laws applicable to our business. Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings with the Securities and Exchange Commission. Unless legally required, Southwestern Energy Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

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OPERATING STATISTICS (Unaudited)
Southwestern Energy Company and Subsidiaries
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2016		2015		2016		2015
Exploration & Production
Production
Gas production (Bcf)		189		228		605		673
Oil production (MBbls)		536		562		1,729		1,696
NGL production (MBbls)		3,068		3,034		9,580		7,374
Total production (Bcfe)		211		249		673		727
Commodity Prices
Average realized gas price per Mcf, including derivatives	$	1.73	$	2.21	$	1.51	$	2.47
Average realized gas price per Mcf, excluding derivatives	$	1.78	$	1.77	$	1.47	$	2.05
Average realized oil price per Bbl	$	35.41	$	33.50	$	28.53	$	35.23
Average realized NGL price per Bbl	$	7.04	$	4.72	$	6.11	$	6.43
Summary of Derivative Activity in the Statement of Operations
Settled commodity amounts included in "Operating Revenues" (in millions)	$	–	$	50	$	–	$	145
Settled commodity amounts included in  "Gain (Loss) on Derivatives" (in millions)	$	(9)	$	49	$	22	$	137
Unsettled commodity amounts included in "Gain (Loss) on Derivatives" (in millions)	$	81	$	(33)	$	(45)	$	(103)
Average unit costs per Mcfe
Lease operating expenses	$	0.86	$	0.92	$	0.87	$	0.92
General & administrative expenses (1)	$	0.23	$	0.20	$	0.21	$	0.22
Taxes, other than income taxes (2)	$	0.10	$	0.10	$	0.09	$	0.11
Full cost pool amortization	$	0.35	$	0.98	$	0.40	$	1.08
Midstream
Volumes marketed (Bcfe)		264		288		814		837
Volumes gathered (Bcf)		145		186		463		620

(1) Excludes $2 million and $71 million of restructuring charges for the three and nine months ended September 30, 2016, respectively.

(2) Excludes $3 million of restructuring charges for the nine months ended September 30, 2016.

STATEMENTS OF OPERATIONS (Unaudited)
Southwestern Energy Company and Subsidiaries
	For the three months ended				For the nine months ended
	September 30,				September 30,
	2016		2015		2016		2015
		(in millions, except share/per share amounts)
Operating Revenues
Gas sales	$	340	$	458	$	906	$	1,540
Oil sales		19		19		50		60
NGL sales		22		14		59		47
Marketing		237		216		631		663
Gas gathering		33		42		106		136
		651		749		1,752		2,446
Operating Costs and Expenses
Marketing purchases		234		213		627		654
Operating expenses		139		176		455		507
General and administrative expenses		61		60		171		188
Restructuring charges		2		–		77		–
Depreciation, depletion and amortization		99		275		349		876
Impairment of natural gas and oil properties		817		2,839		2,321		4,374
(Gain) loss on sale of assets, net		–		1		–		(276)
Taxes, other than income taxes		24		27		69		84
		1,376		3,591		4,069		6,407
Operating Loss		(725)		(2,842)		(2,317)		(3,961)
Interest Expense
Interest on debt		59		51		168		153
Other interest charges		8		2		12		54
Interest capitalized		(41)		(53)		(123)		(155)
		26		–		57		52
Gain (Loss) on Derivatives		71		15		(28)		30
Loss on Early Extinguishment of Debt		(51)		–		(51)		–
Other Income, Net		3		–		–		2
Loss Before Income Taxes		(728)		(2,827)		(2,453)		(3,981)
Provision (Benefit) for Income Taxes
Current		–		–		–		7
Deferred		(20)		(1,088)		(20)		(1,539)
		(20)		(1,088)		(20)		(1,532)
Net Loss		(708)		(1,739)		(2,433)		(2,449)
Mandatory convertible preferred stock dividend		27		27		81		79
Net Loss Attributable to Common Stock	$	(735)	$	(1,766)	$	(2,514)	$	(2,528)
Loss Per Common Share
Basic	$	(1.52)	$	(4.62)	$	(6.02)	$	(6.65)
Diluted	$	(1.52)	$	(4.62)	$	(6.02)	$	(6.65)
Weighted Average Common Shares Outstanding
Basic		482,485,150		382,098,080		417,222,661		379,909,748
Diluted		482,485,150		382,098,080		417,222,661		379,909,748

BALANCE SHEETS (Unaudited)
Southwestern Energy Company and Subsidiaries
	September 30, 2016		December 31, 2015
	(in millions)
ASSETS
Current assets	$	1,889	$	393
Property and equipment		24,290		24,364
Less: Accumulated depreciation, depletion and amortization		(19,501)		(16,821)
Total property and equipment, net		4,789		7,543
Other long-term assets		212		150
Total assets		6,890		8,086
LIABILITIES AND EQUITY
Current liabilities		649		707
Long-term debt		4,651		4,704
Pension and other postretirement liabilities		51		50
Other long-term liabilities		416		343
Total liabilities		5,767		5,804
Equity:
Common stock, $0.01 par value; 1,250,000,000 shares authorized; issued 493,446,371 shares as of September 30, 2016 (does not include 2,043,780 shares issued on October 17, 2016, on account of a dividend declared on September 21, 2016) and 390,138,549 as of December 31, 2015		5		4
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 6.25% Series B Mandatory Convertible, $1,000 per share liquidation preference, 1,725,000 shares issued and outstanding as of September 30, 2016 and December 31, 2015, conversion in January 2018		–		–
Additional paid-in capital		4,673		3,409
Accumulated deficit		(3,515)		(1,082)
Accumulated other comprehensive loss		(39)		(48)
Common stock in treasury; 31,269 shares as of September 30, 2016 and 47,149 as of December 31, 2015		(1)		(1)
Total equity		1,123		2,282
Total liabilities and equity	$	6,890	$	8,086

STATEMENTS OF CASH FLOWS (Unaudited)
Southwestern Energy Company and Subsidiaries
	For the nine months ended
	September 30,
	2016		2015
	(in millions)
Cash Flows From Operating Activities
Net loss	$	(2,433)	$	(2,449)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, depletion and amortization		349		877
Impairment of natural gas and oil properties		2,321		4,374
Amortization of debt issuance costs		12		50
Deferred income taxes		(20)		(1,539)
Loss on derivatives, net of settlement		48		105
Stock-based compensation		24		18
Gain on sales of assets, net		–		(276)
Restructuring charges		30		–
Loss on early extinguishment of debt		51		–
Other		5		2
Change in assets and liabilities		(50)		65
Net cash provided by operating activities		337		1,227
Cash Flows From Investing Activities
Capital investments		(391)		(1,392)
Acquisitions		–		(582)
Proceeds from sale of property and equipment		434		704
Other		–		7
Net cash provided by (used in) investing activities		43		(1,263)
Cash Flows From Financing Activities
Payments on current portion of long-term debt		(1)		(1)
Payments on long-term debt		(1,175)		(500)
Payments on short-term debt		–		(4,500)
Payments on revolving credit facility		(3,268)		(2,168)
Borrowings under revolving credit facility		3,152		2,148
Payments on commercial paper		(242)		(5,179)
Borrowings under commercial paper		242		5,699
Change in bank drafts outstanding		(19)		26
Proceeds from issuance of long-term debt		1,191		2,200
Debt issuance costs		(17)		(17)
Proceeds from issuance of common stock		1,247		669
Proceeds from issuance of mandatory convertible preferred stock		–		1,673
Preferred stock dividend		(27)		(52)
Other		(4)		–
Net cash provided by (used in) financing activities		1,079		(2)
Increase (decrease) in cash and cash equivalents		1,459		(38)
Cash and cash equivalents at beginning of year		15		53
Cash and cash equivalents at end of period	$	1,474	$	15

SEGMENT INFORMATION (Unaudited)
Southwestern Energy Company and Subsidiaries	Exploration
	and
	Production		Midstream		Other		Eliminations		Total
	(in millions)
Three months ended September 30, 2016
Revenues	$	378	$	682	$	–	$	(409)	$	651
Marketing purchases		–		578		–		(344)		234
Operating expenses		181		23		–		(65)		139
General and administrative expenses		50		11		–		–		61
Restructuring charges		2		–		–		–		2
Depreciation, depletion and amortization		83		16		–		–		99
Impairment of natural gas and oil properties		817		–		–		–		817
Taxes, other than income taxes		22		2		–		–		24
Operating income (loss)		(777)		52		–		–		(725)
Capital investments(1)		179		1		–		–		180
Three months ended September 30, 2015
Revenues	$	488	$	747	$	–	$	(486)	$	749
Marketing purchases		–		615		–		(402)		213
Operating expenses		228		32		–		(84)		176
General and administrative expenses		50		10		–		–		60
Depreciation, depletion and amortization		255		20		–		–		275
Impairment of natural gas and oil properties		2,839		–		–		–		2,839
(Gain) loss on sale of assets, net		–		1		–		–		1
Taxes, other than income taxes		26		1		–		–		27
Operating income (loss)		(2,910)		68		–		–		(2,842)
Capital investments(1)		461		7		–		–		468
Nine months ended September 30, 2016
Revenues	$	998	$	1,862	$	–	$	(1,108)	$	1,752
Marketing purchases		–		1,533		–		(906)		627
Operating expenses		586		71		–		(202)		455
General and administrative expenses		141		30		–		–		171
Restructuring charges		74		3		–		–		77
Depreciation, depletion and amortization		300		49		–		–		349
Impairment of natural gas and oil properties		2,321		–		–		–		2,321
Taxes, other than income taxes		62		7		–		–		69
Operating income (loss)		(2,486)		169		–		–		(2,317)
Capital investments(1)		372		3		1		–		376
Nine months ended September 30, 2015
Revenues	$	1,633	$	2,451	$	1	$	(1,639)	$	2,446
Marketing purchases		–		2,025		–		(1,371)		654
Operating expenses		670		103		2		(268)		507
General and administrative expenses		158		30		–		–		188
Depreciation, depletion and amortization		824		52		–		–		876
Impairment of natural gas and oil properties		4,374		–		–		–		4,374
(Gain) loss on sale of assets, net		1		(277)		–		–		(276)
Taxes, other than income taxes		77		7		–		–		84
Operating income (loss)		(4,471)		511		(1)		–		(3,961)
Capital investments(1)		1,880		164		10		–		2,054

(1) Capital investments includes increases of $27 million and $6 million for the three months ended September 30, 2016 and 2015, respectively, and decreases of $24 million and $5 million for the nine months ended September 30, 2016 and 2015, respectively, relating to the change in accrued expenditures between periods. E&P capital for the nine months ended September 30, 2015 includes approximately $516 million related to the WPX Property and Statoil Property Acquisitions. Midstream capital for the nine months ended September 30, 2015 includes approximately $119 million associated with the intangible asset related to the firm transportation acquired through the WPX Property Acquisition.