southwestern energy july 2015 update

July 2015 Update

NYSE: SWN

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

[email protected] [email protected]

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.

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)

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 SHALE2014 Reserves: 5,069 Bcf (47%)

2014 Production: 494 Bcf (64%)

Net Acres: 888,161 (12/31/14)

B

SOUTHWEST APPALACHIA2014 Reserves: 2,297 Bcfe (22%)

Dec 2014 Production: 370 Mmcfe/d

Net Acres: 443,376 (Jan 2015)(2)

C

NORTHEAST APPALACHIA2014 Reserves: 3,192 Bcf (30%)

2014 Production: 254 Bcf (33%)

Net Acres: 312,773 (Jan 2015)(1)

RESERVES & PRODUCTION2014 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

LATX

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

$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

1.241.34

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)

1.52.2

3.7

4.95.9

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)


(4)

2,657

3,619

4,100

4,528

4,8364,819

5,3565,440

07 08 09 10 11 12 13 14

Lateral Length

Continuous Improvement

6

17.5

13.6

11.710.9

7.9

6.76.2

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

4,7955,069

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

4,2234,070

4,9824,752

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

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)

ID Operator Well NameIP

(Mmcfe/d)IP30

(Mmcfe/d)

Lateral Length(feet)

% Liquidsat 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

67

9

1

3

4

8

1

2

3

Marcellus

Utica

Upper Devonian

67

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

9

Northeast Appalachia


• 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.

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.

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).

Fayetteville30%

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)


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


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)

13

• Invest in the Highest PVI Projects

• Maintain Strong Balance Sheet

• Deliver the Numbers

• Curiosity to Learning to Innovation to

The Road to

14

Appendix

About Southwestern

Source: Public company reports, Southwestern Energy

-

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

XO

M

CH

K

AP

C

SW

N

SW

N

CO

G

SW

N

DV

N

CO

P

BP

SW

N

EQ

T

SW

N

AR

CV

X

BH

P

SW

N

EO

G

RR

C

EC

A

UP

L

SW

N

CN

X

WP

X

TL

M

RD

S/A

LIN

E

NB

L

SM

QE

P

OX

Y

XE

C

AP

A

RIC

E

CL

R

PX

D

MR

O

NF

X

XC

O

SD

US Lower 48 Gas Production Sorted by 1Q15 (MMcf/d)

SWN is 4th overall as of 1Q15

1Q14

1Q111Q12

1Q13

1Q15

1Q10

1Q09

SW

N

SW

N

SW

N

SW

N

SW

N

SW

N

SW

N

• Strategy built on the Formula: The Right People doing the Right Things, wisely investing the cash flow from the

underlying Assets will create Value +.

$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


Total Volumes Hedged 240 Bcf

% of Estimated Gas Production 25%

Average Price per MMBtu $ 4.40

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Bcd

/dSouthwestern’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


Transco

ET Rover

Constitution

Columbia Gas

Tennessee

Millennium

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

Pro

du

ctio

n R

ate

(mcf

e/d

)

Days on Production

9 BCFe Type Curve (Based on LL = 7,500 ft) 12 BCFe Type Curve (Based on LL = 7,500 ft)

15 BCFe Type Curve (Based on LL = 7,500 ft) Wells Put to Sales in 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

Pro

du

ctio

n R

ate

(m

cfe

/d)

Days on Production

10.6 Bcfe Upper Devonian Type Curve (Based on LL = 7500 ft)

Southwest Appalachia – Type Curves

18

Marcellus – Dry Gas RegionEUR: 100% Gas

Marcellus – Wet Gas RegionEUR: ~51% Gas, 1% Condensate, 48% NGLs

UticaEUR: 100% Gas

Upper DevonianEUR: ~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

Pro

du

ctio

n R

ate

(mcf

e/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

Pro

du

ctio

n R

ate

(mcf

e/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)

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

Gro

ss P

rod

uct

ion

(Mm

cf/d

)

Northeast Appalachia Horizontal Well Performance


• 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.

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

Da

ily R

ate

, 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

0

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

2,200

Gro

ss

Pro

du

cti

on

(M

Mc

fpd

)

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

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



Fayetteville Shale Horizontal Well Performance

22Notes: 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

35033181 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

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

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

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.


A r k a n s a s

L o u i s i a n a

Te

xa

s

Camden

El Dorado

MagnoliaTexarkana

Bastrop

Bossier City

MindenMonroe

RustonShreveport

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 UnionMorehouse

WestCarroll

Richland

Franklin

Lincoln

OuachitaBienville

Jackson

NevadaDrew

Ashley

Ouachita Calhoun

Bradley

Columbia Union

0 10 20Miles

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


Oil Field

Gas Field

OBO well

SWN Drilled

Johnson-Vert

Shut in

SWN 2014 Plan

Doles


1

2

34

6

Dean-Vert


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

12Sharp-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

Drilling & Completion Major Cost CategoriesAverage Fayetteville Shale Well Cost Estimate


Major Cost Categories

27

U.S. Dry Gas

Production

U.S. Gas

ConsumptionNet Imports

Source: EIA

U.S. Gas Consumption and Sources

U.S. gas production and

consumption rising

in recent years.

Bcf

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

29

U.S. Natural Gas Supply and Demand12 Month Rolling Average

Source: EIA

30

U.S. Gas Drilling and Prices

Gas Rigs

Drilling

Gas Price

$/MMBtu

Source: Baker Hughes, Bloomberg

Gas Rigs

Gas Price

31

$/Bbl $/MMBtu

Source: Bloomberg

Oil and Gas Price Comparison

Henry Hub

Natural Gas

(right scale)

WTI Crude

(left scale)

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.

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


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)

($ 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


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$


2015 2014

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


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.

southwestern energy july 2015 update

News & Politics