PowerPoint presentation from Southwestern Energy posted in early July (before 2Q15 numbers were released). Southwestern is now the fourth largest natural gas producer in the Lower 48 States and one of the largest producers in the Marcellus Shale region.

1. July 2015 Update
NYSE: SWN

2. 1
Southwestern Energy Company
• General Information •
Southwestern Energy Company is an independent natural gas company whose wholly-owned subsidiaries
are engaged in natural gas and oil exploration and production and natural gas gathering and marketing.
• Investor Contacts •
Steve Mueller
Chairman and Chief Executive Officer
Phone: (832) 796-4700 Fax: (832) 796-4820
Craig Owen
Senior Vice President and Chief Financial Officer
Phone: (832) 796-2808 Fax: (832) 796-4820
• Market Data as of June 30, 2015 •
Institutional Ownership – 92.2%
Management and Board Ownership – 0.6%
Shares of Common Stock Outstanding – 384,600,000
Market Capitalization – $8,742,000,000
NYSE: SWN
52-Week Price Range – $21.63 (3/10/15) – $44.99 (7/1/14)
Investment Grade Credit Rating – Moody’s (Baa3); S&P (BBB-); Fitch (BBB-)
Michael Hancock
Director, Investor Relations
Phone: (832) 796-7367 Fax: (832) 796-4820
craig_owen@swn.com michael_hancock@swn.com

3. 2
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 fund the company’s planned capital investments; 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 various areas and, in particular, the Fayetteville
Shale, Northeast Appalachia and Southwest Appalachia as well as relative to other productive shale gas plays; the company’s ability to realize the
expected benefits from recent acquisitions; the impact of title and environmental defects and other matters on the value of the properties acquired in
the company’s recent acquisitions and any other future acquisitions; difficulties in integrating the company’s operations as a result of any significant
acquisitions; the impact of government regulation, including any legislation relating to hydraulic fracturing, the climate or over-the-counter derivatives;
the costs and availability of oil field personnel services and drilling supplies, raw materials and equipment, including pressure pumping equipment
and crews; the company’s ability to determine the most effective and economic fracture stimulation; the company’s future property acquisition or
divestiture activities; the effects of weather; increased competition and regulation; the financial impact of accounting regulations and critical
accounting policies; the comparative cost of alternative fuels; the different risks and uncertainties associated with proposed activities in Canada;
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.
Forward-Looking Statements
The contents of this presentation are current as of July 1, 2015.

4. 3
Southwestern Energy Consistently Creates Value
• Strategy built on the formula
– The Right People doing the Right Things, wisely investing the cash flow from the underlying Assets will create Value +
• 4th largest producer of natural gas in the U.S. Lower 48 for 1Q 2015
– 2014 production of 768 Bcfe
– 10.7 Tcfe of proved reserves at December 2014
• World-class assets
– High degree of operational control and flexibility
– Access to all major markets
• Demonstrated capital discipline
– Average return on equity(1) of 15% over the past three years
– Target $1.30 of present value cash flow, discounted at 10%, for each dollar invested (defined as 1.3 PVI)
– Commitment to maintain investment grade credit profile
• Differentiating focus on low-cost structure with proven track record
– From 2009 – 2014:
• 21% compound annual production growth and per share growth
• 24% compound annual reserve growth and per share growth
– Cash operating costs(2) of $1.32 per Mcfe in 2014
(1) Excludes impact of full cost ceiling test impairments
(2) Cash operating costs for 2014 include lease operating expenses ($0.91/Mcfe), general and administrative expenses ($0.24/Mcfe), taxes other than income taxes ($0.11/Mcfe) and net
interest expense ($0.06/Mcfe)

5. Sand Wash Basin – Approx. 376,000 net acres
Brown Dense – Approx. 304,000 net acres
New Brunswick – Approx. 2.5 million net acres
Other New Ventures – Approx. 982,000 net acres
D
A
FAYETTEVILLE SHALE
2014 Reserves: 5,069 Bcf (47%)
2014 Production: 494 Bcf (64%)
Net Acres: 888,161 (12/31/14)
B
SOUTHWEST APPALACHIA
2014 Reserves: 2,297 Bcfe (22%)
Dec 2014 Production: 370 Mmcfe/d
Net Acres: 443,376 (Jan 2015)(2)
C
NORTHEAST APPALACHIA
2014 Reserves: 3,192 Bcf (30%)
2014 Production: 254 Bcf (33%)
Net Acres: 312,773 (Jan 2015)(1)
RESERVES & PRODUCTION
2014 Reserves: 10,747 Bcfe
2014 Production: 768 Bcfe
2015 Estimated Production: 940-955 Bcfe
4
North American Areas of Operation
D
C
D
D
NEW VENTURES
LA
TX
CO
OK AR
WV
PA
NB
(!) Includes approximately 46,700 net acres that were acquired as part of transaction closed in January 2015
(2) Includes approximately 30,000 net acres that were acquired as part of transaction closed in January 2015
A
EXPLORATION
B
Forward-Looking Statement

6. $675
$1,362 $1,383
$1,602
$1,774
$1,638
$1,997
$2,320
07 08 09 10 11 12 13 14
Adjusted EBITDA
($MM)
2.70
1.70
0.91
1.24
1.34
2.08
0.62
1.29
07 08 09 10 11 12 13 14
F&D Cost ($/Mcfe)
113
195
300
405
500
565
657
768
07 08 09 10 11 12 13 14
Production
(Bcfe)
1.5
2.2
3.7
4.9
5.9
4.0
7.0
10.7
07 08 09 10 11 12 13 14
Proved Reserves
(Tcfe)
Proven Track Record
5
(1) Adjusted EBITDA is a non-GAAP financial measure. See explanation and reconciliation of adjusted EBITDA on page 35.
(2) Average realized gas prices ($/Mcf)
(3) Excludes reserve revisions
(4) Excludes the impact from the West Virginia and southwest Pennsylvania acquisition closed in December 2014.
$6.80 $7.52 $5.35 $4.62 $4.18 $3.44 $3.65Price(2) $3.72
(1)
(3)
Forward-Looking Statement
(4)

7. 2,657
3,619
4,100
4,528
4,836
4,819
5,356
5,440
07 08 09 10 11 12 13 14
Lateral
Length
Continuous Improvement
6
17.5
13.6
11.7
10.9
7.9
6.7
6.2
6.8
07 08 09 10 11 12 13 14
Days to Drill
$2.9
$3.0
$2.9
$2.8$2.8
$2.5
$2.4
$2.6
07 08 09 10 11 12 13 14
Well Cost
($ in millions)
$2.39
$1.44
$0.80
$1.04
$1.11
$2.53
$0.45
$1.14
07 08 09 10 11 12 13 14
F&D Cost
($ per Mcf)
716
1,545
3,117
4,345
5,104
2,988
4,795
5,069
07 08 09 10 11 12 13 14
Reserves
(in Bcf)
54
135
244
350
437
486 486 494
07 08 09 10 11 12 13 14
Production
(in Bcf)
Notes: Finding and development costs exclude revisions and capital investments in our sand facility, drilling rig related and ancillary equipment.
-61% +608%+815%-11%+105% -52%
25.6
16.5
13.2 12.9
10.2
10 11 12 13 14
Days to Drill
3,805
4,223
4,070
4,982
4,752
10 11 12 13 14
Lateral
Length
$5.9
$7.0
$6.2
$7.0
$6.1
10 11 12 13 14
Well Cost
($ in millions)
1
23
54
151
254
10 11 12 13 14
Production
(in Bcf)
-60% +25%
$2.98
$1.38
$1.03
$0.73
$0.85
10 11 12 13 14
F&D Cost
($ per Mcf)
38
342
816
1,963
3,192
10 11 12 13 14
Reserves
(in Bcf)
Northeast Appalachia
Fayetteville Shale

8. Enhanced Position in Core Areas of Premier Play
Forward-Looking Statement7
SWN acreage shown
in yellow
Bcf/Section
50 Bcf
100 Bcf
150 Bcf
200 Bcf
250 Bcf
300 Bcf
1Q15 Appalachia Production vs. Peers(1) Unconventional Appalachia Net Acres vs. Peers(1)
(1) Source: Company presentations and filings
(2) Includes impact from STO and WPX property acquisitions closed in January 2015
(in thousands)(Mmcfe/d)
• SWN held approximately 413,000 net
acres in West Virginia and southwest
Pennsylvania as of December 31, 2014
• In January 2015, additional transaction
for approximately 30,000 net acres closed
• Plan to participate in 50 to 55 wells in
2015, primarily in the Marcellus wet gas
window
(2)(2)

9. ID Operator Well Name
IP
(Mmcfe/d)
IP30
(Mmcfe/d)
Lateral
Length
(feet)
% Liquids
at IP30
MARCELLUS
1 SWN Melvin Kahle 8H 7.9 4,507 58%
2 EQT Pierce Pad (8 wells) 15.4 5,814 0%
3 SWN Gladys Briggs 8H 13.8 5,142 40%
4 SWN Esther Clark 3H 5.2 6,556 0%
5 NBL SHR1 Pad (6 wells) 10.1 8,741 19%
6 AR Mash Unit (2 wells) 15.7 9,835 28%
7 AR Ruth Unit 1H 19.2 6,514 14%
8 SWN Edwin Bunner 8H 4.2 5,600 0%
9 CNX AUD3 6.1 8,691 0%
UTICA
1 SWN Hubbard 3H 11.1 8.1 3,550 0%
2 HES NAC 3H-3 11.0 5,336 0%
3 RRC Sportsman's Club 11H 59.0 5,420 0%
4 RICE Bigfoot 9H 41.7 14.0 6,957 0%
5 CVX Conner 6H 25.0 6,451 0%
6 GST Simms 4-5H 29.4 19.8 4,447 0%
7 SWN Messenger 3H 25.0 20.0 5,889 0%
8 SGY Pribble 6H 30.0 3,605 0%
9 MHR S. Winland #1300H 46.5 4,289 0%
UPPER DEVONIAN
1 CNX NV39F 3.0 2.9 4,889 0%
2 EQT 7 Well Avg. 8.2 5,964 0%
3 EQT 11 Well Avg. 5.0 4,396 18%
Well-Positioned in Rapidly Developing Play
8
2
4
5
6
7
9
1
3
4
8
1
2
3
Marcellus
Utica
Upper Devonian
6
7
9
2
5
All SWN operated rates exclude shut in days
Acquired acreage is low-risk opportunity
in the heart of world-class play
Source: Public data and company presentations
8
3
1

10. 9
Northeast Appalachia
Forward-Looking Statement
• We hold approximately 312,000 net acres in Northeast Pennsylvania.
• Gross operated production was 1,148 MMcf/d from 348 operated horizontal wells as
of March 31, 2015.
• We plan to drill 88 to 92 operated horizontal wells in 2015.

11. Fayetteville Shale Focus Area
10 Forward-Looking Statement
• SWN holds approx. 888,000 net acres in the Fayetteville Shale play.
• SWN discovered the Fayetteville Shale and has first mover advantage – average acreage cost of
$320 per acre with a 15% royalty and average working interest of 74%.
• We plan to drill approximately 225 to 235 operated horizontal wells in 2015.
Notes: Data as of March 31, 2015. Rates are AOGC Form 13 and Form 3 test rates.

12. Capital Investments
$0
$500
$1,000
$1,500
$2,000
$2,500
2010 2011 2012 2013 2014 2015
Exploration Drilling Development Drilling Leasehold & Seismic
Property Acquisitions Midstream Services Drilling Rigs
Corporate & Other Capital Expense & Other E&P
$2,120 $2,207
$2,081
$2,235
$2,440
BY SPENDING TYPE in $Millions
E&P capital program heavily weighted to low-risk development drilling in 2015.
Plan to invest approximately $700 million in Northeast Appalachia $645 million in the
Fayetteville Shale and $520 million in Southwest Appalachia in 2015 (including Midstream).
Fayetteville
30%
NE
Appalachia
37%
SW
Appalachia
27%
Exploration
and Other
6%
E&P
BY DIVISION
2015
44%
33%
23%
2014
$2,015
(1)
(1) Excludes acquisition capital for transactions announced in 4Q 201411
(1)
Forward-Looking Statement

13. 12
(1) Includes amounts associated with assets divested in 2015.
(2) Adjusted net income and adjusted EBITDA exclude unrealized gains and losses on derivative contracts. All are non-GAAP financial measures. See explanation and reconciliation on pages 34 and 35.
(3) Net cash flow is net cash flow before changes in operating assets and liabilities and excludes current taxes associated with any future asset sales. Net cash flow is a non-GAAP financial measure.
See explanation and reconciliation on page 33.
(4) Excludes acquisition capital for transactions announced in 4Q 2014.
(5) The impact of preferred dividends is included in Adjusted EBITDA and excluded from Net Cash Flow.
Our Path Forward
Forward-Looking Statement
 Adj. Net Income(2)
2014
Actual
 Net Cash Flow(3)(5)
 CapEx(4)
$4.41 Gas
$92.91 Oil
 Adj. EBITDA(2)(5)
 Debt %
NYMEX Price Assumption
2015 Guidance
$801 MM
$2,270 MM
$2,440 MM
$2,320 MM
39%
$215-$235 MM
$1,760-$1,780 MM
$2,015 MM
$1,645-$1,665 MM
39%-41%
$140-$160 MM
$1,640-$1,660 MM
$2,015 MM
$1,525-$1,545 MM
40%-42%
$240-$260 MM
$1,800-$1,820 MM
$2,015 MM
$1,680-$1,700 MM
39%-41%
$3.25 Gas
$50.00 Oil
$3.00 Gas
$60.00 Oil
$3.25 Gas
$60.00 Oil
(1)

14. 13
• Invest in the Highest PVI Projects
• Maintain Strong Balance Sheet
• Deliver the Numbers
• Curiosity to Learning to Innovation to
The Road to

15. 14
Appendix

16. About Southwestern
Source: Public company reports, Southwestern Energy
-
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
XOM
CHK
APC
SWN
SWN
COG
SWN
DVN
COP
BP
SWN
EQT
SWN
AR
CVX
BHP
SWN
EOG
RRC
ECA
UPL
SWN
CNX
WPX
TLM
RDS/A
LINE
NBL
SM
QEP
OXY
XEC
APA
RICE
CLR
PXD
MRO
NFX
XCO
SD
US Lower 48 Gas Production Sorted by 1Q15 (MMcf/d)
SWN is 4th overall as of 1Q15
1Q14
1Q11
1Q12
1Q13
1Q15
1Q10
1Q09
SWN
SWN
SWN
SWN
SWN
SWN
SWN
• Strategy built on the Formula: The Right People doing the Right Things, wisely investing the cash flow from the
underlying Assets will create Value +.

17. $4.40 $4.40 $4.40 $4.40
0
10
20
30
40
50
60
70
80
90
100
110
120
130
140
150
1Q 2Q 3Q 4Q
16
2015 Gas Hedges in Place
Bcf
Fixed Price
Forward-Looking Statement
Total Volumes Hedged 240 Bcf
% of Estimated Gas Production 25%
Average Price per MMBtu $ 4.40

18. 0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
Bcd/d
Southwestern’s Appalachia Takeaway
17
Industry agreements for ~4 Bcf/d incremental takeaway capacity in northeast PA and ~10 Bcf/d in southwest PA / West
Virginia / Ohio between 2015 and 2018 have been executed and will provide new outlets for the industry.
Estimated SWN
Marketed Volumes at
Jan 1, 2015
Firm Sales
Forward-Looking Statement
Transco
ET Rover
Constitution
Columbia Gas
Tennessee
Millennium

19. 0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
0 100 200 300 400 500 600 700 800 900 1000
ProductionRate(mcfe/d)
Days on Production
9 BCFe Type Curve (Based on LL =7,500 ft) 12 BCFe TypeCurve(Based on LL = 7,500 ft)
15 BCFe TypeCurve(Based on LL = 7,500 ft) Wells Put to Salesin Prior 18 Months (Avg. LL =6,200 ft)
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
10,000
0 100 200 300 400 500 600 700 800 900 1000
ProductionRate(mcfe/d)
Days on Production
10.6 Bcfe Upper Devonian Type Curve (Based on LL = 7500 ft)
Southwest Appalachia – Type Curves
18
Marcellus – Dry Gas Region
EUR: 100% Gas
Marcellus – Wet Gas Region
EUR: ~51% Gas, 1% Condensate, 48% NGLs
Utica
EUR: 100% Gas
Upper Devonian
EUR: ~51% Gas, 1% Condensate, 48% NGLs
Source: Company data
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
0 100 200 300 400 500 600 700 800 900 1000
ProductionRate(mcfe/d)
Days on Production
16.5 BCF Utica Type Curve (Based on LL = 7,500 ft) James Messenger 3H
0
1000
2000
3000
4000
5000
6000
7000
0 100 200 300 400 500 600 700 800 900 1000
ProductionRate(mcfe/d)
Days on Production
4 BCFe Type Curve (Based on LL = 7,500 ft) 7 BCFe Type Curve (Based on LL = 7,500 ft)
10 BCFe Type Curve (Based on LL = 7,500 ft) Wells to Sales in Prior 20 Months (Avg. LL = 7,100 ft)

20. 0
100
200
300
400
500
600
700
800
900
1,000
1,100
1,200
Sep-10 Mar-11 Sep-11 Mar-12 Sep-12 Mar-13 Sep-13 Mar-14 Sep-14 Mar-15
GrossProduction(Mmcf/d)
Northeast Appalachia
Horizontal Well Performance
19 Forward-Looking Statement
• Gross operated production of 1,148 MMcf/d
as of March 31, 2015
• Firm takeaway capacity in NE Appalachia
of more than 1.3 Bcf/d
Time Frame
30th-Day
Avg Rate
(# of wells)
Average
Completed
Lateral
Length (ft)
Average RE-
RE
(Rig Days)
Average
Completed
Well Cost
($MM)
3rd Qtr 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) 4,371 11.6 $6.6
3rd Qtr 2013 4,470 ( 22) 4,740 11.5 $7.3
4th Qtr 2013 7,589 ( 20) 6,116 10.2 $7.1
1st Qtr 2014 7,009 ( 21) 3,859 10.5 $6.2
2nd Qtr 2014 6,772 ( 23) 4,982 10.3 $6.3
3rd Qtr 2014 6,159 ( 18) 5,288 10.0 $6.3
4th Qtr 2014 6,922 (26) 5,333 10.0 $5.9
1st Qtr 2015 8,217 ( 12) 5,090 11.2 $5.8
Proven History of Effectively Ramping Activity Quickly
Gross operated production of approx.
1,148 MMcf/d as of March 31, 2015.

21. Northeast Appalachia
Well Performance by County
20
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
0 365 730 1095 1460
DailyRate,Mcf/d
Days of Production
Production by County
Bradford County Lycoming County Susquehanna County Wells on-line < 18 months
8 BCF Type Curve 12 BCF Type Curve 16 BCF Type Curve
Note: Excludes downtime
Company Operated Drilled Wells

22. 0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
2,000
2,200
GrossProduction(MMcfpd)
Gross operated production was approx.
2,038 MMcf/d as of March 31, 2015.
Pipeline
Curtailment
Issues
Weather
Curtailment
Issues
SWN Gross Operated Production
Fayetteville Shale
Horizontal Well Performance
Note: Data as of March 31, 2015.
• Gross operated production of
2,038 MMcf/d as of March 31, 2015
• 2014 Fayetteville Shale F&D cost
of $1.14/Mcf
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
2007 255 1,682 1,416 (253) 1,238 ( 253) 2,657
2008 329 2,778 2,400 (329) 2,149 ( 328) 3,619
2009 446 3,475 2,666 (446) 2,369 ( 444) 4,100
2010 553 3,363 2,530 (553) 2,244 ( 551) 4,528
2011 560 3,328 2,546 (560) 2,205 ( 560) 4,836
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) 1,975 ( 126) 5,165
3rd Qtr 2013 89 4,597 2,696 (89) 2,391 ( 89) 5,490
4th Qtr 2013 97 4,901 2,798 (97) 2,553 ( 97) 5,976
1st Qtr 2014 105 4,272 2,616 (105) 2,205 ( 105) 5,680
2nd Qtr 2014 148 4,369 2,720 (148) 2,112 ( 148) 5,382
3rd Qtr 2014 106 4,303 2,680 (106) 2,174 (106) 5,202
4th Qtr 2014 97 4,840 2,472 (97) 1,856 ( 95) 5,547
1st Qtr 2015 99 4,357 2,502 (63) 1,915 ( 33) 5,875
21

23. 0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
4,500
5,000
0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500
Days of Production
Mcf/d
4 Bcf Typecurve
3 Bcf Typecurve
2 Bcf Typecurve
All Wells
Wells with Laterals >5000' DLL
Wells with Laterals >4000' DLL
Wells with Laterals >3000' DLL
Fayetteville Shale
Horizontal Well Performance
22
Notes: Data as of December 31, 2014. Excludes shut-in wells and wells with mechanical problems (114).
598 472
300 252 131189913 886 827 764 682 631 584 534
2048 2005 1908 1783 1661 1574 1489 1385 9871301
358504
11071210
469
862
417
3503
3181 19593038 25793452 2838 23162942 2147
Total
Well
Count
24573336 2694 1625 14631798
3064 3014 2901 2747 2607 2511 2409 2155 20392266 10791902 1742 1566 1408 1241
733
>3,000 ft
Well
Count
>4,000 ft
Well
Count
>5,000 ft
Well
Count

24. AR
Midstream
23
FAYETTEVILLE SHALE GATHERING
Gathered Volumes at March 31, 2015 (Bcf/d) 2.3
Gathering Lines (Miles) 2,029
Firm Transportation Capacity (Bcf/d) 2.0
Compression Equipment (Horsepower) 589,305
2015 Estimated EBITDA ($MM)(1) $275 - $285
(1) EBITDA is a non-GAAP financial measure. See explanation and reconciliation on page 35. Forward-Looking Statement
SWN MARKETING
2015 Estimated Discount to NYMEX Gas ($/Mcf) $0.70 - $0.85
2015 Estimated Gas Volumes Marketed (Bcf) 1,030 – 1,050
2015 Estimated EBITDA ($MM)(1) $45 - $55

25. Black Oil
Condensate
& Volatile Oil
Dry Gas
Exploration – Sand Wash Basin Niobrara
• Proven Hydrocarbon System
• Niobrara vertical prod since 1920’s with avg. 130 MBOE/well
• Contiguous 380,000 Net Acres in AOI
• 75% fee, 15% federal, 10% state
• Thick, Continuous Section
• Favorable reservoir characteristics for resource play development
• Forward focus on Condensate and Volatile Oil Windows
• Southwestern's Activity
• Drilled four vertical and one horizontal Niobrara wells in 2014
• 3 well program planned in 2015 (2 horizontal and 1 vertical)
24
Diamond T Sheep
7-92 1-26
Welker 42-11
Welker 6-92 1-2H11
Dill Gulch 1-22
North Hayden 1-26
4.5
Miles
90
N
2014 Wells

26. 25
Brown Dense Exploration Project
• SWN currently holds 304,000 net acres in Lower Smackover Brown Dense play. Total land cost
of $831 per acre; 81% NRI; most leases have 3-year terms and 3 to 4-year extensions.
• Targeting oil and wet gas window in Upper Jurassic age, kerogen-rich carbonate in southern
Arkansas and northern Louisiana.
 Targeting 300 to 550 feet thick section at depths of 8,000 - 11,000 feet.
• Currently analyzing recently acquired 75 square miles of 3-D seismic data in Union Parish.
Forward-Looking Statement
A r k a n s a s
L o u i s i a n a
Texas
Camden
El Dorado
MagnoliaTexarkana
Bastrop
Bossier City
Minden
Monroe
Ruston
Shreveport
West Monroe
-4,000-5,000
-6,000
-7,000
-9,000
-8,000
-14,000
-12,000
HempsteadLittle River
Miller
Lafayette
Bowie
Cass
Caddo
Bossier
Marion
Harrison
Webster
Claiborne Union
Morehouse
West
Carroll
Richland
Franklin
Lincoln
Ouachita
Bienville
Jackson
Nevada
Drew
Ashley
Ouachita Calhoun
Bradley
Columbia Union
0 10 20
Miles
Legend
Oil and Gas Fields
Product
Gas
Oil
Rodessa
Monroe
Gas
Field
Roberson (TA’d)
Peak=103 bo+180 mcfEast
Texas
Arkoma
Basin
Fayetteville
Shale
Garrett
Peak=301 bc+1720 mcf
BML
Peak=421 bc+3900 mcf
Oil Field
Gas Field
OBO well
SWN Drilled
Johnson-Vert
Shut in
SWN 2014 Plan
Doles
Peak=435 bc+2500 mcf
1
2
3
4
6
Dean-Vert
Peak=214 bc+1207 mcf
5
Dean-Hzl
Peak=43 bc + 618 mcf
7
Hollis-Vert (SI)
Peak=37 bo+428 mcf
9
McMahen-Vert (SI)
Peak=17 bo+299mcf
10
Plum Creek 13-Vert (SI)
Peak=75 bo+184 mcf
11
Milstead-Vert
Peak=28 bo+161 mcf
12 Sharp-Vert
Peak=600 bo+1300 mcf
8
Benson-Vert
Peak=706 bo+2132 mcf
3
14
Plum Creek 23-Vert
Peak=68 bc+247 mcf
13

27. Drilling & Completion Major Cost Categories
Average Fayetteville Shale Well Cost Estimate
26 Forward-Looking Statement
Major Cost Categories

28. 27
U.S. Dry Gas
Production
U.S. Gas
Consumption
Net Imports
Source: EIA
U.S. Gas Consumption and Sources
U.S. gas production and
consumption rising
in recent years.
Bcf

29. U.S. Electricity Generation
28
Electricity Generation by Energy Source
1. Geothermal, solar, wood, waste and wind
2. Petroleum and others gases
Source: EIA
Total 4,085 Billion KWh (Mar 2014 – Feb 2015).
1
2

30. 29
U.S. Natural Gas Supply and Demand
12 Month Rolling Average
Source: EIA

31. 30
U.S. Gas Drilling and Prices
Gas Rigs
Drilling
Gas Price
$/MMBtu
Source: Baker Hughes, Bloomberg
Gas Rigs
Gas Price

32. 31
$/Bbl $/MMBtu
Source: Bloomberg
Oil and Gas Price Comparison
Henry Hub
Natural Gas
(right scale)
WTI Crude
(left scale)

33. 32
2015 2014 2014 2013 2012
($ in millions, except per share amounts)
Revenues 933$ 1,113$ 4,038$ 3,371$ 2,730$
Adjusted EBITDA(1)
492$ 623$ 2,320$ 1,998$ 1,638$
Adjusted Net Income(2)
84$ 231$ 801$ 704$ 487$
Net Cash Flow(1)
493$ 617$ 2,270$ 1,985$ 1,599$
Adjusted Diluted EPS(2)
0.22$ 0.66$ 2.27$ 2.00$ 1.39$
Production (Bcfe) 233 182 768 657 565
Avg. Realized Gas Price ($/Mcf) 2.99$ 4.19$ 3.72$ 3.65$ 3.44$
Avg. Realized Oil Price ($/Bbl) 30.90$ 100.43$ 79.91$ 103.32$ 101.54$
Finding Cost ($/Mcfe)(3)
1.81$ 0.62$ 2.08$
Reserve Replacement (%)(3)
520% 501% 163%
Total Debt/Proved Reserves ($/Mcfe) 0.48$ (4)
0.26$ (4)
0.65$ 0.28$ 0.42$
Total Debt/Avg. Daily Production ($/Mcfe) 2,084$ 904$ 3,309$ 1,084$ 1,081$
Net Debt/Total Capitalization 42% 32% 60% 35% 35%
Year Ended December 31,
($ in millions, except per share amounts)
Quarter Ended March 31,
Financial & Operational Summary
(1) Net cash flow is net cash flow before changes in operating assets and liabilities. Diluted cash flow per share is net cash flow divided by the diluted weighted average common shares
outstanding disclosed in the company’s financial statements. Net cash flow, Adjusted EBITDA and diluted CFPS are non-GAAP financial measures.
(2) Adjusted net income and adjusted diluted EPS exclude non-cash ceiling test impairments and gains (losses) on derivatives, net of settlement, and both are non-GAAP financial measures.
See explanations and reconciliations on page 34.
(3) Excludes reserve revisions and excludes capital investments in our sand facility, drilling rig related and ancillary equipment.
(4) Calculated using end of the year proved reserves disclosed in the Company’s Annual Report on Form 10-K for the preceding year.

34. 33
We report our 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 our 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. These adjusted amounts are not a measure of
financial performance under GAAP.
Explanation and Reconciliation of Non-GAAP
Financial Measures: Net Cash Flow
Forward-Looking Statement
2015 2014 2014 2013 2012
Cash flow from operating activities:
Net cash provided by operating activities 541$ 609$ 2,335$ 1,909$ 1,654$
Add back (deduct):
Change in operating assets and liabilities (48) 8 (65) 76 (55)
Net cash flow 493$ 617$ 2,270$ 1,985$ 1,599$
$3.00 Gas $3.25 Gas $3.25 Gas
$60.00 Oil $50.00 Oil $60.00 Oil
($ in millions)
Cash flow from operating activities:
Net cash provided by operating activities $1,640 - $1,660 $1,760 - $1,780 $1,800 - $1,820
Add back (deduct):
Assumed change in operating assets and liabilities - - -
Net cash flow $1,640 - $1,660 $1,760 - $1,780 $1,800 - $1,820
NYMEX Commodity Price Assumption
2015 Guidance
12 Months Ended December 31,
($ in millions)
3 Months Ended March 31,
($ in millions)

35. ($ in millions (per share) ($ in millions (per share) ($ in millions) (per share)
Net income (loss) 924$ 2.62$ 704$ 2.00$ (707)$ (2.03)$
Add back:
Impairment of natural gas and oil properties, net of taxes - - - - 1,193$ 3.42$
Adjustments due to discrete tax items (46) (0.13) 13 0.04 - -
Loss (gain) on derivatives excluding derivatives, settled (net of taxes) (80)$ (0.23)$ (13)$ (0.04)$ 1$ -
Transaction costs (net of taxes) 3$ 0.01$ - - - -
Adjusted net income 801$ 2.27$ 704$ 2.00$ 487$ 1.39$
2014 2013 2012
12 Months Ended December 31,
34
Additional non-GAAP financial measures we may present from time to time are adjusted net income and adjusted diluted earnings per share attributable to
Southwestern Energy stockholders, both of 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.
Explanation and Reconciliation of Non-GAAP
Financial Measures: Adjusted Net Income
(1) Primarily relates to the exclusion of certain discrete tax adjustments due to a redetermination of deferred state tax liabilities to reflect updated state apportionment factors
and the recognition of an income tax valuation allowance for state net operating losses. The company expects its 2015 effective income tax rate to be 38.5%.
(1)
($ in millions) (per share) ($ in millions) (per share)
Net income attributable to common stock: 46$ 0.12$ 194$ 0.55$
Add back:
Loss (gain) on derivatives excluding derivatives, settled (net of taxes) 11$ 0.03$ 37$ 0.11$
Transaction costs (net of taxes) 27$ 0.07$ -$ -$
Adjusted net income 84$ 0.22$ 231$ 0.66$
3 Months Ended December 31,
2015 2014

36. 2015 Guidance(3)
NYMEX Commodity Price Assumption Midstream
$3.00 Gas $3.25 Gas $3.25 Gas Services
$60.00 Oil $50.00 Oil $60.00 Oil Segment
($ in millions)
Net Income Attributable to Common Stock $140 - $160 $215 - $235 $240 - $260 $155 - $165
Add back: Preferred Dividends 106 - 106 106 - 106 106 - 106 -
Adj. Net Income Attributable to SWN 246 - 266 321 - 341 346 - 366 155 - 165
Add back:
Provision for income taxes 154 - 167 201 - 213 217 - 229 97 - 103
Interest expense 20 - 25 20 - 25 20 - 25 10 - 20
Depreciation, depletion and amortization 1,185 - 1,195 1,185 - 1,195 1,185 - 1,195 54 - 56
Less: Preferred Dividends 106 - 106 106 - 106 106 - 106 -
EBITDA $1,525 - $1,545 $1,645 - $1,665 $1,680 - $1,700 $325 - $335
3 Months Ended
March 31, 12 Months Ended December 31,
2015 2014 2014 2013 2012(1) 2011 2010 2009(1) 2008 2007
($ in millions)
Net income (loss) $78 $194 $924 $704 ($707) 638 $604 ($37) $568 $221
Add back:
Net interest expense 51 13 59 42 35 24 26 19 29 24
Provision (benefit) for income taxes 49 129 525 486 (443) 413 392 (16) 351 136
Depreciation, depletion and amortization 293 225 942 787 2,751 705 590 1,402 414 294
Less: Unrealized gains (losses) on
derivatives 21 62 130 21 (2) 6 10 (15) - -
Adjusted EBITDA (2) $492 $623 $2,320 $1,998 $1,638 $1,774 $1,602 $1,383 $1,362 $675
35
EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Adjusted EBITDA is defined as EBITDA less
gains and/or losses on derivatives (net of settlement). Southwestern has included information concerning EBITDA and Adjusted EBITDA because they are
used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in
the energy industry. EBITDA and Adjusted EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating
activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the company's
profitability or liquidity. EBITDA and Adjusted EBITDA, as defined above, may not be comparable to similarly titled measures of other companies. Net income
is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles historical Adjusted
EBITDA with historical net income.
Explanation and Reconciliation of Non-GAAP
Financial Measures: Adjusted EBITDA
Forward-Looking Statement
The table below reconciles forecasted Adjusted EBITDA with forecasted net income for 2015, assuming various NYMEX price scenarios and the corresponding
estimated impact on the company's results for 2015, including current hedges in place:
(1) Includes impact from full cost ceiling test impairment of our natural gas and oil properties.
(2) As reported in the quarterly report filed with the SEC, this amount excludes the impact from preferred dividends. However, the guidance table below includes the impact of preferred dividends as part of EBITDA.
(3) Excludes impacts from assets previously announced to be divested during 2015.