Latest Investor Presentation

October 2017 Update

Enhancing our Future

NYSE: SWN

1

Southwestern Energy Company

General InformationSouthwestern Energy Company is a leading natural gas and oil company with operations

predominantly in the United States, engaged in exploration, development, production,

natural gas gathering and marketing activities.

Bill Way

President & Chief Executive Officer

Phone: (832) 796-4791

Fax: (832) 796-4820

Jennifer Stewart

Senior Vice President &

Chief Financial Officer - Interim

Phone: (832) 796-7770

Fax: (832) 796-4820

[email protected]

Michael Hancock

Vice President, Investor Relations

Phone: (832) 796-7367

Fax: (832) 796-4820

[email protected]

Investor Contacts

2

Forward-Looking Statements

This presentation includes 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 (including geographic basis differentials); changes in expected

levels of natural gas and oil reserves or production; operating hazards, drilling risks, unsuccessful exploratory activities; natural disasters; 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 in service or other costs related to drilling and completion activities; potential

liability for remedial actions under existing or future environmental regulations; failure to obtain necessary regulatory approvals; 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.

Cautionary Note to U.S. Investors – The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and

possible reserves. We use the terms "resource" and “EUR” in this presentation that the SEC’s guidelines prohibit us from including in filings with

the SEC. The quarterly reserves data included in this release are estimates we prepared that have not been audited by our independent reserve

engineers. All such estimates are inherently more speculative than estimates of proved reserves and are subject to substantially greater risk of

actually being realized. U.S. investors are urged to consider closely the oil and gas disclosures and associated risk factors in our Form 10-K

and other reports and filings with the SEC. Copies are available from the SEC and from the SWN website.

This presentation contains non-GAAP financial measures, such as adjusted net income, adjusted EBITDA and net cash flow, including certain

key statistics and estimates. 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. Please see the Appendix for

definitions and reconciliations of the non-GAAP financial measures that are based on reconcilable historical information.

The contents of this presentation are updated as of October 26, 2017 unless otherwise indicated.

3

Our Strategy

• Further strengthening of the balance sheet

• Invest within cash flow

• Proactive risk management

Rigorous financial discipline

• Investment return exceeds $1.30 of present value cash flow,

discounted at 10%, for each dollar invested (1.3 PVI)

• Capital allocation based on highest return projects

Value focused capital allocation

and investment practices

• Delivering robust value growth in core Appalachia areas

underpinned by cash flow from vast Fayetteville asset

• High degree of operational control and flexibilityPremier quality, large scale assets

• Well enhancements and cost optimization, improving

returns and expanding inventory

• Leading FT portfolio capturing improving basis differentials

• Value creation across gas value chain

Increasing capital efficiency

and margin expansion

• Superior reservoir performance

• Maximizing resource access through leading drilling precision

• Optimizing completion techniques to enhance well

productivity and economics

Leading technology, operating

and commercial capabilities

4

Strategy Delivering ResultsRecent Highlights

Margin

Expansion

Q3 Highlights

Well Results

• Total net production of 232 Bcfe, including 153 Bcfe from the Appalachian Basin, up 10% and

26%, compared to 3Q 2016, respectively

• Significantly improved debt maturity profile through successful notes offering, resulting in

approximately $92 million in bond debt due prior to 2022

• Realized C3+ NGL prices of $27.82 per barrel, or 58% of WTI (net of transportation costs),

up 75% compared to the 3Q 2016

• Added to 2018 hedge position which now has ~473 Bcf hedged at an average floor price of

approximately $3/Mcf with upside potential on over 62% of hedged volumes

• Progressed Tioga County development with first four-well development pad delivering initial

production rate of over 80 MMcf per day

• Placed a three-well pad to sales in western Susquehanna County acreage with combined

maximum rate of over 62 MMcf per day

• Demonstrated repeated reservoir deliverability with second Company-drilled Utica well

• Brought two additional encouraging Moorefield delineation wells online continuing to confirm our

geologic and reservoir modeling of the play

• Renegotiated Fayetteville transportation agreement, increasing 2018 cash flow by ~$45 million,

subject to FERC approval

• Commenced water infrastructure project in SW Appalachia that is expected to reduce total well

costs by approximately $500,000 per well beginning in late 2018

• Created approximately $1.4 million per well of incremental value from immediately reduced

processing rates in the lean gas acreage of Southwest Appalachia while providing a competitive

dry gas gathering solution in southern Utica acreage

5

Strengthen the Balance SheetDebt Maturity Schedule

• Cash balance and undrawn revolver anchors liquidity position of approximately $1.8B(1)

• Extended maturity profile with no significant bond maturities before 2022

• Use of September bond offering proceeds used to prepay unsecured 2020 term loan in full

and reduce balance of 2020 notes

$0

$500

$1,000

$1,500

$2,000

17 18 19 20 21 22 23 24 25 26 27

$ M

Ms

No significant

maturities until 2022

$0

$500

$1,000

$1,500

$2,000

Cash 20

$ M

Ms

Secured Term Loan

(1) Excludes outstanding letters of credit and minimum liquidity covenant.

(2) Assumes 90% of 2020 notes retired or extended beyond 2020 prior to October 2019; otherwise, facility matures in 2019. As of September 30, 2017, the Company has successfully retired or

extended 89% of the 2020 notes.

(3) Maturities of $40 million retired upon maturity in October 2017.

(2) (3)

Cash Balance vs Secured Term Loan Bond Maturity Schedule

6

Asset Overview

Reserves & Production2016 Production: 875 Bcfe

2016 Reserves: 5,253 Bcfe

March 31, 2017 Reserves: >10 Tcfe*

AR

WV

PANortheast Appalachia

2016 Reserves – 1,574 Bcf (30%)

2016 Production – 350 Bcf (40%)

Net acres – 245,805 (12/31/16)

Southwest Appalachia

2016 Reserves – 677 Bcfe (13%)

2016 Production – 148 Bcfe (17%)

Net acres – 321,563 (12/31/16)

Fayetteville Shale

2016 Reserves – 2,997 Bcf (57%)

2016 Production – 375 Bcf (43%)

Net acres – 918,535 (12/31/16)

Gross Drilling Locations Remaining for

Assumed NYMEX Gas Prices(1)

$3.00 $3.50 $4.00

SW Appalachia 1,925 3,400 4,200

NE Appalachia 375 500 550

Fayetteville 675 1,575 1,575

SWN Total 2,975 5,475 6,325

(1) Assumes 10% return

* Unaudited

7

Premier Asset Optionality

• 3 large-scale, low-risk assets provide diversification of cash flow

through geographic location and product mix

43%

20%

37%

YTD 2017

Revenue

Profile

NE Appalachia SW Appalachia Fayetteville

44%

36%

20%

SW App

Revenue

Breakout

Gas

NGLs

Oil

36%

31%

33%

3/31/2017

Reserves

Profile

NE Appalachia SW Appalachia Fayetteville

8

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

$1.40

2013 2014 2015 2016 Fay NE App SW App Rich

SW AppLean

$1.33$1.23

$0.88$0.75

$1.03

$0.40$0.56

$0.28

PD

P F

&D

(1)

(1) See explanation and reconciliation of proved developed (PDP) F&D on page 44.

(2) Displayed F&D costs for potential development opportunities represents a hypothetical well based on

expected average CLAT for full-field development. Capital based on $/foot from February 2017 guidance:

(1) For more information on SW App Rich and Lean wells, see slides 30 and 31.

• Decreasing proved developed F&D costs resulting from deliberate portfolio investment shift to Appalachia

• Increased EUR’s in NE Appalachia due to changes in completion intensity and flowback methods

• Reducing costs through differentiating vertical integration capabilities and improving cycle times

Increasing Capital EfficiencyImproving F&D

Historical F&D Results F&D of Potential Development Opportunities(2)

Estimates Capital EUR CLAT

Fayetteville $3.1 MM 3 Bcf 5,300’

NE App $4.8 MM 12 Bcf 5,500’

SW App Rich(3) $6.7 MM 12 Bcfe 7,500’

SW App Lean(3) $6.7 MM 24 Bcfe 7,500’

(3) (3)

9

Southwest AppalachiaCore position in premier play targeting stacked pays

SWN acreage shown in yellow

Gas in Place Map

Bcf/Section

50 Bcf

100 Bcf

150 Bcf

200 Bcf

250 Bcf

300 Bcf

• Total resource potential of 45 Tcfe with 4,200

locations

• Asset optionality provides flexibility to maximize

value based on market conditions

– Well-positioned to capture improving liquids

pricing

• Drilling and completion optimization resulting in

enhanced productivity and value

• Company operated water infrastructure expected to

be in operation in late 2018

• Delineation of Utica progressing

• Targeting exit rate production growth of over 50%

in 2017, compared to 2016

Operational excellence driving

inventory and margin expansion

10

Southwest AppalachiaIncreasing Capital Efficiency

• Completion

enhancements showing

increased production at

higher pressures

• Early indications showing

improved productivity

across the rich and lean

gas windows

• Gen 2 completions

outperforming Gen 1

completions by ~30%

(1) 3-Phase Production normalized to 7,500’ CLAT.

0

250

500

750

1,000

1,250

1,500

0 30 60 90 120 150 180

Cum

ula

tive P

roductio

n

(MM

cfe

)(1)

Producing Days

LINDA

GREATHOUSE

0

1,000

2,000

3,000

4,000

5,000

0 90 180 270 360 450 540

Cum

ula

tive P

roductio

n

(MM

cfe

)(1)

Producing Days

ALICE EDGE

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

0 90 180 270

Cum

ula

tive P

roductio

n

(MM

cfe

)(1)

Producing Days

WILLIAM RITCHEA

Completion

Design

Sand

Loading

(lb/ft)

Cluster

Spacing

(ft)

Previous Operator

Design1,000 – 1,300 45 - 110

Gen 1 2,000 65

Gen 2 2,000 – 5,000 35 - 65

ALICE EDGE

LINDA

GREATHOUSE

WILLIAM RITCHEA

11

$2.8

$0.9$0.5

$1.4

$1.6

$1.3

$2.2

$0.1

$3.1

$0

$2

$4

$6

$8

$10

$12

Gen 2Completions

WaterProject

WilliamsProcessingAgreement

Current ExtendedLaterals

CompletionOptimization

PriceOptionality

Incre

menta

l S

ingle

Well

NP

V 1

0 (

$M

Ms)

$2.8$2.3

$0.5

$2.3

$1.3$1.4

$1.8

$0.7

$0

$2

$4

$6

$8

$10

$12

Gen 2Completions

WaterProject

Current ExtendedLaterals

CompletionOptimization

PriceOptionality

Incre

menta

l S

ingle

Well

NP

V 1

0 (

$M

Ms)

• Significant incremental value being created through operational enhancements and

value chain expansion with large upside remaining

Southwest AppalachiaIncremental Value Creation

• Driving economic expansion

– Standard design – 7,500’ CLAT, Gen 1 completion designs, optimized lateral placement, drawdown management

– Gen. 2 completions – Tighter stage spacing and higher sand loadings

– Water project – Company operated water infrastructure lowering per barrel cost

– Williams processing agreement – Reduced gathering and processing rates

– Extended laterals – 9,000’ CLAT

– Completion optimization – Continued tighter stage spacing with optimized sand loadings based on learnings

– Price optionality – $0.25/Mcf uplift in gas price, $5.00/Bbl uplift in oil price or $2.50/Bbl uplift in NGL price

Gas

Condensate

NGL

Gas

Condensate

NGL

Rich Gas Lean Gas

12

Southwest AppalachiaWater Infrastructure

Commenced water infrastructure project to

capture additional value

– Expected to generate savings of

$500,000 per well beginning in late

2018, an ~8% improvement in F&D

– Reduces break-even gas price by

~$0.25/Mcf

– Increases the operational capability for

development

– Improves logistics and reduces trucking

traffic and costs

– Opportunity to capture 3rd party

business, enhancing economics even

further

13

• Over the next 4 years, executed transportation agreements will provide a pathway for ~12 BCF/d of

production to leave the Southwest Appalachian region

– Certificates were awarded and construction has commenced on ~3.5 BCF/d of takeaway with expected in-

service of late 2017

• SWN transportation portfolio structured to provide access to high demand markets along the Gulf Coast

while also capturing materially improving in-basin pricing

– Approximately 50% of SW App to be sold at premium Gulf Coast markets beginning in 2018

Southwest AppalachiaImproving basis differentials as a result of pipeline infrastructure

(1) Basis information shown above is based on market quotes as of October 10, 2017 and assumes sales locations percentages shown on page 29.

($0.76)

($0.37)

($0.22)

SW App

Estimated Weighted Average Sales Differential

(excluding transportation)(1)

2017 2018 2019

-

5

10

15

20

25

30

Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22

Bcf/

d

Southwest Appalachia Takeaway

Existing Industry Capacity

Future Industry Capacity

14

$7.04

$14.47 $15.91

$27.82

Q3 2016 Q3 2017 Q3 2016 Q3 2017

Southwest AppalachiaIncreasing NGL realizations driving economics in SW Appalachia

60%25%

10%

5%

Ethane Propane Butane Other

Increasing NGL RealizationsNGL Composition

35%

of WTI

58%

of WTI

30%

of WTI

16%

of WTI

Total NGL Realizations

(after transport costs) C3+ Realizations

(after transport costs)

• Realized over 100% increase in NGL pricing compared to 3Q 2016

• Positive outlook for continued strengthening NGL economics

• Well positioned to capture improving ethane prices through firm transportation capacity

• 5% increase in NGL realizations increases cash flow by $30 - $40 MM per year

• Each $2.50/Bbl increase in NGL price reduces breakeven gas price by ~$0.50/Mcf

15

0

12,000

24,000

36,000

48,000

60,000

0

500

1,000

1,500

2,000

2,500

U.S

. E

nd

ing

Sto

cks o

f E

tha

ne

(M

bb

ls)

Eth

an

e D

em

an

d (

Mb

/d)

Ethane Demand & Inventory(1)

Cracker Demand Exports (Land) Exports (Water) Inventory

Southwest AppalachiaIncreasing NGL realizations driving enhanced economics

• SWN ethane take-away portfolio provides direct exposure to Mont

Belvieu pricing utilizing ATEX capacity

• New ethane cracker demand and export capacity expected to further

strengthen ethane pricing

• NGL exposure provides optionality to maximize returns based on

pricing environment

$-

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

$0.45

Mont Belvieu Ethane Pricing ($/gal)(2)

Increase of over 100% since January 2016

and over 20% from current prices

(1) Source – Genscape and EIA data

(2) Source – OPIS & NYMEX ethane strip pricing information shown above is based on market quotes as of October 4, 2017

16

Northeast AppalachiaDelivering value now and in the future

• Gross operated production of 1,408 MMcf/d (1,166 MMcf/d net) as of Sept 30, 2017

• Achieved division’s record all-time gross operated production in 3Q 2017, an increase

of ~35% compared to 3Q 2016

• Low cost integrated firm transportation portfolio provides access to improving pricing

locations which is expected to enhance margins significantly in 2018

• Improved productivity being driven by optimization of completion and flowback methods

across the play

• Successful delineation results in Tioga area, preparing approximately 28,000 net acres

for development drilling

SWN Acreage

17

Northeast Appalachia Improving basis differentials driving margin expansion

• SWN transportation portfolio structured to capture materially improving Northeast basis

differentials

• Added approximately 140 MMcf per day of new takeaway capacity in 2Q 2017 to the

portfolio at an average cost of $0.10 per Mcf, facilitating future growth

• Basis improvement expected to increase cash flow by over 50% over the next 3 years

– A $0.05/mcf improvement in differentials provides ~$20 MM impact to cash flow

(1) Basis information shown above is based on market quotes as of October 10, 2017 and assumes sales locations percentages shown on page 33.

($0.60)

($0.34)

($0.26)

NE App

Estimated Weighted Average Sales Differential

(excluding transportation)(1)

2017 2018 2019

$1.12 $1.00$0.74 $0.66

$0.85

$1.31

16 17 18 19

Improving Margin

LOE TOTI G&A Differentials Margin

Normalized for $3.00 NYMEX

$3.00 NYMEX

18

Northeast AppalachiaCompletions and flowback optimization enhancing economics

• Susquehanna County initial EUR increase of over 25% compared to previous operational

design due to changes in completion intensity and flowback methods

• Cumulative production increase of ~75% in the first year of production

• Learnings being applied across our acreage position with repeatable productivity

improvements expected

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

0 73 146 219 292 365

Ave

rage C

um

ula

tive

P

roduction p

er

Well

(MM

cf)

Days of Production

Susquehanna County Cumulative Production

Optimized Operational Design (54 Wells) Previous Operational Design (199 Wells)

19

FayettevilleSignificant asset with upside promise

SWN Acreage

• Fayetteville E&P and midstream assets have generated over $1.0 billion in free cash flow in

the last three years and are expected to generate approximately $425 million in 2017,

supporting the growth in the Appalachian Basin

• Gross operated production was 1,232 MMcf/d (814 MMcf/d net) as of Sept 30, 2017

• Close proximity to growing Gulf Coast demand and access to LNG export facilities

• Aggressively pursuing operational and commercial opportunities to drive enhanced

economics

• Confirmed Moorefield productivity with positive results from recent delineation wells

• Base production enhancements directed to improve overall cash margin

20

• SWN has the lowest production base decline of peers due to the influence of later life

shallower declining Fayetteville

• Low base decline and robust hedging program ensures stability of future cash flow

0%

10%

20%

30%

40%

50%

60%

Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 SWN

Base D

eclin

e (

%)

Base Decline by Operator(1)

FayettevilleShallowing Base Declines

(1) Source: RSEG report from September 2017 (Peers include Antero, Cabot, Chesapeake, Consol, EQT, Eclipse, RICE and Range)

21

Building for Tomorrow

Fayetteville

Southwest

Appalachia

Northeast

Appalachia

• Driving down breakeven thresholds to expand inventory at lower commodity prices

• Applying ongoing technical learnings to maximize future investment economics

• Strengthening the balance sheet through EBITDA expansion and opportunistic debt reduction

• Extracting value across multiple areas of the value chain

• Unlocking 45 Tcfe resource potential by targeting stacked pays

• Exercising flexibility within asset to capture enhanced returns

• Further de-risking Utica following two delineation wells demonstrating repeated reservoir deliverability

• Achieving productivity enhancements through well design optimization

Company

Objectives

• Applying recent completion enhancements across the acreage resulting in improved productivity

• Successfully delineating additional acreage in Tioga, Wyoming and western Susquehanna Counties

• Building on operational momentum to generate free cash flow(1)

• Realizing improved basis differentials as infrastructure is placed in service

• Generating free cash flow(1) from sizable production base with shallowing declines

• Advancing geologic understanding of the Moorefield and other Fayetteville benches

• Maximizing price realizations through proximity to increasing Gulf Coast demand

(1) Free cash flow is calculated as net cash flow less capital investments.

22

Delivering Shareholder Value+

• Rigorous financial discipline

• Proactive risk management

• Value-driven growth within cash flow

• Driving differentiation through

environmental and regulatory

standards

• Enhancing value from vertical

integration

• Margin expansion through cost

reductions and improved well

productivity

• Operational and technical excellence

2323

Appendix

24

Rigorous Financial Discipline

Strengthen the balance sheet• No significant near-term maturities

• Strong liquidity position of approximately $1.8B(1)

• Targeting long-term net debt to EBITDA of <2.0x

Invest within cash flow• Fully funded 2017 capital program

• Returns focused with flexibility to align activity with commodity prices

• Target investments meeting or exceeding 1.3 PVI at strip pricing

• Delivering value-driven growth

Proactive risk management• Provide protection of cash flows and ensure targeted returns with a

rolling 3-year hedge program

• Utilize a combination of commodity and basis hedging

• Protect against challenging commodity price environment while

retaining exposure to price upside through swaps and collars

(1) Excludes outstanding letters of credit and minimum liquidity covenant.

25

Net Cash Flow

Stringent Capital Allocation and Investment PracticesFully Funded 2017 Capital Program

(1) $500MM of proceeds from July 2016 equity offering earmarked to accelerate drilling and completions activity, with approximately $200MM expected to be invested in 2017.

(2) Assumes midpoint of guidance issued in February 2017.

(3) Net cash flow is net cash flow before changes in operating assets and liabilities and is a non-GAAP financial measure. See explanation and reconciliation on page 40.

• Dynamic portfolio management and vertical integration allowing flexibility to align activity with strip pricing

• Investment decisions made based on highest PVI ranking utilizing strip pricing

• Appalachian production expected to grow approximately 40% based on exit production rates and

approximately 17% (using midpoints) over 2016 annual production volumes

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,100

$200

$1,225 MM$1,300 MM

2017

Sources

2017 Capital

Investments

Drilling & completions $810 - $860

Land, seismic & other E&P$115 - $130

Midstream & corporate$25 - $40

Capitalized interest & expense$225 - $245

Capital

Investment

Breakdown(2)

Capital Investments Proceeds from 2016 Equity Issuance

$ in millions

(2,3)

(1)

(2)

26

139

127

114 116 116

164

0

20

40

60

80

100

120

140

160

180

200

Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 2019

Vo

lum

es

He

dg

ed

, (B

cf)

Swaps 2-Way Costless Collars 3-Way Costless Collars

$2.40 x $2.97 x $3.37

$2.40 x $2.97 x $3.37

$2.39 x $2.97 x $3.37

$2.97 x $3.56

$3.02 $3.02 $3.02

$2.29 x $2.97 x $3.30

$2.96 x $3.38

$3.06

$3.02

$2.40 x $2.97 x $3.37

$2.50 x $2.95 x $3.32

$3.01

HedgingProtecting balance sheet and targeted returns

(1) Based on an average swap or purchased put strike price.

Note: Please refer to our quarterly report for the three months and nine months ended September 30, 2017 on Form 10-Q, filed with the Securities and Exchange Commission,

for complete information on the Company’s commodity, basis and interest rate protection.

Hedge Summary

2017 REM 2018 2019

Swaps 73 178 57

2-Way Collars 32 23 –

3-Way Collars 34 272 108

Total (Bcf) 139 472 164

Avg. Floor Price(1) $3.01 $2.99 $2.97

2727

Southwest Appalachia

28

Well-Positioned in Core Utica Acreage

*Drilled and completed by previous operator.

(1) Source: Public data and company presentations

ID Operator Well NameLateral Length

(ft)

UTICA

1 SWN* Hubbard 3H 5,889

2 SWN* Messenger 3H 5,821

3 SWN OE Burge 501H 8,061

4 SWN Marlin Funka 9H 4,572

1 RRC Claysville 11H 5,420

2 CVX Conner 6H 6,451

3 EQT Scotts Run 591340 3,221

4 CNX GH 9 6,141

5 GST Simms 5H 4,447

6 SGY Pribble 6H 3,605

Repeated Utica Delineation Success

• Initial productivity in the top quartile of

WV and PA Utica industry wells(1)

• O.E. Burge 501H

– Surpassed 3 Bcf of cum production in 8

months of flowing time

– Sustained production at a flat rate of 15

MMcf per day at ~4,000 PSI casing

pressure

• Marlin Funka 9H

– 1 Bcf of cum production in 2 months of

flowing time

– Average 60-day rate of 17.7 MMcf per

day as part of pressure management

program

29

Southwest Appalachia TakeawayIncreasing Gulf Coast market exposure

• No transportation fees associated with firm sales

• Assumes SWN Rover and TransCanada capacity in service in late 2017 and late 2018, respectively

• Ability to release capacity or buy third-party production to fill any excess transportation capacity

• Sales location percentages are based on fully utilized transportation and firm sales volumes

Firm Sales Firm Transportation Capacity

ETC Rover

Columbia Gas Transmission MXP (project not in service)

Year

SWN Firm

Transport

(MMbtu/d)

Reservation

Rate per

MMbtu

Firm Sales

(MMbtu/d)

Rate per

MMbtu

Total Firm

Takeaway

(MMbtu/d)

Annual

WAVG Rate

per MMbtu

2017 94,000 $0.23 196,000 $0.00 290,000 $0.07

2018 360,000 $0.64 101,000 $0.00 461,000 $0.50

2019 777,000 $0.62 55,000 $0.00 832,000 $0.58

2020 777,000 $0.62 92,000 $0.00 869,000 $0.56

4%

48%54% 52%

23%

21%

35%33%

59%

21%

6% 10%14% 10%

5% 5%

0%

20%

40%

60%

80%

100%

2017 2018 2019 2020

Sales Locations

Nymex

M2

TCO

Gulf

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

Bcf/

d

TransCanada MXP

ETC Rover

Firm Transportation Capacity

Firm Sales

30

0

1,500

3,000

4,500

6,000

7,500

9,000

10,500

0 100 200 300 400 500 600 700 800

Mm

cfe

/d

Days Online

Historical Production 12 BCFe Type Curve 14 BCFe Type Curve

Southwest Appalachia Rich GasHorizontal well performance

Well Results Exceeding Expectations

Time Frame

Wells Placed

on

Production

Average

Lateral

Length

Average

Completed

Well Cost

$MMs

(# of wells)1

Avg Rate

For 1st 30

Days (Mcfe/d)

(# of wells)

30th-Day

% Gas /

Condensate

/ NGL

Avg Rate

For 1st 60 Days

(Mcfe/d)

(# of wells)

60th-Day

% Gas /

Condensate /

NGL

2nd Qtr 2015 10 5,353 $8.7 (1) 7,275 (10) 41 / 11 / 48 7,084 (10) 41 / 10 / 49

3rd Qtr 2015 5 5,599 $6.7 (5) 7,027 (5) 34 / 17 / 49 7,391 (5) 35 / 15 / 50

4th Qtr 2015 15 8,520 $8.1 (10) 7,101 (15) 32 / 23 / 44 7,605 (15) 33 / 22 / 45

1st Qtr 2016 - - - - - - -

2nd Qtr 2016 5 5,643 $6.0 (5) 5,347 (5) 29 / 31 / 40 5,367 (5) 30 / 29 / 41

3rd Qtr 2016 - - - - - - -

4th Qtr 2016 6 6,486 $5.5 (3) 4,820 (6) 35 / 23 / 42 5,548 (6) 36 / 21 / 43

1st Qtr 2017 9 7,972 $7.8 (7) 7,338 (9) 36 / 17 / 47 8,054 (9) 37 / 16 / 47

2nd Qtr 2017 9 7,811 $6.7 (9) 7,233 (9) 30 / 28 / 42 8,193 (9) 31 / 26 / 43

3rd Qtr 2017 4 7,832 $6.2 (4) 4,497 (4)2 30 / 28 / 42 6,551 (4)2 30 / 26 / 44

(1) Includes only wells drilled and completed by SWN.

(2) Temporarily restricted production during the quarter. The average rate on the 60th day was 10,600 Mcfe/d.

33%

47%

20%

Production Mix

Gas

NGL

Oil

SWN Drilled & Completed Rich Gas Condensate

(Normalized to 7,500 ft lateral)

31

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

0 100 200 300 400 500 600 700 800

Mm

cfe

/d

Days Online

Historical Production 24 BCFe Type Curve 26 BCFe Type Curve

Time Frame

Wells Placed

on

Production

Average

Lateral

Length

Average

Completed

Well Cost

$MMs

(# of wells)1

Avg Rate

For 1st 30

Days (Mcfe/d)

(# of wells)

30th-Day

% Gas /

Condensate

/ NGL

Avg Rate

For 1st 60 Days

(Mcfe/d)

(# of wells)

60th-Day

% Gas /

Condensate /

NGL

2nd Qtr 2015 - - - - - - -

3rd Qtr 2015 - - - - - - -

4th Qtr 2015 4 4,431 $5.3 (4) 7,150 (4) 53 / 6 / 41 7,803 (4) 54 / 5 / 41

1st Qtr 2016 - - - - - -

2nd Qtr 2016 6 4,493 $4.9 (6) 5,765 (6) 52 / 9 / 40 5,977 (6) 52 / 7 / 40

3rd Qtr 2016 - - - - - - -

4th Qtr 2016 - - - - - - -

1st Qtr 2017 4 6,593 $7.0 (4) 5,821 (4) 54 / 5 / 41 7,199 (4) 54 / 5 / 41

2nd Qtr 2017 6 6,756 $9.5 (2)2 8,057 (6) 48 / 4 / 48 9,208 (6) 48 / 4 / 48

3rd Qtr 2017 10 6,016 $6.6 (10) 5,381 (8) 54 / 3 / 43 6,310 (8) 55 / 2 / 43

Southwest Appalachia Lean GasHorizontal well performance

Well Results Exceeding Expectations

(1) Includes only wells drilled and completed by SWN.

(2) Includes additional capital related to completions testing

53%47%

1%

Production Mix

Gas

NGL

Oil

SWN Drilled & Completed Lean Gas Condensate

(Normalized to 7,500 ft lateral)

3232

Northeast Appalachia

33

13% 11%18% 20%

49% 51%48% 47%

33% 31% 29% 28%

5% 7% 5% 5%

0%

20%

40%

60%

80%

100%

2017 2018 2019 2020

Sales Locations

Gulf

M3

Dominion

Other

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

Bcf/

d

Northeast Appalachia TakeawayLow cost portfolio with extensive market reach

• No transportation fees associated with firm sales

• Assumes Constitution in service in Mid 2019

• Ability to release capacity or buy third-party production to fill excess transportation capacity


• Assumes all extensions exercised

Firm Sales

Transport Extension Options


Constitution

Added ~140 MMcf per day of new

takeaway capacity @ $0.10 per Mcf to

facilitate further growth

Year

SWN Firm

Transport

(MMbtu/d)

Reservation

Rate per

MMbtu

Firm Sales

(MMbtu/d)

Rate per

MMbtu

Total Firm

Takeaway

(MMbtu/d)

Annual

WAVG Rate

per MMbtu

2017 1,199,000 $0.28 149,000 $0.00 1,348,000 $0.25

2018 1,307,000 $0.30 143,000 $0.00 1,450,000 $0.27

2019 1,376,000 $0.30 73,000 $0.00 1,449,000 $0.29

2020 1,363,000 $0.29 35,000 $0.00 1,398,000 $0.28

34

Northeast AppalachiaContinued improvement

2016 PDP F&D of $0.59(1)

25.6

16.5

13.2 12.910.2 10.0 9.0

10 11 12 13 14 15 16

$5.9

$7.0$6.2

$7.0

$6.1$5.4 $5.3

10 11 12 13 14 15 16

3,602

4,2234,070

4,9824,752

5,403

6,142

10 11 12 13 14 15 16

-10%

Days to Drill Well Cost ($MM)

Production (Bcf)

+61%

-65%

123

54

151

254

360 350

10 11 12 13 14 15 16

Lateral Length (ft.)

(1) See definition and reconciliation on page 53.

Operating StatisticsTime Frame

# of wells

placed to

sales

Average

Completed

Lateral

Length (ft)

Average

Completed

Well Cost

($MM)

Avg Rate

for 1st

30 Days

(Mcfe/d)

(# of wells)

Avg Rate

for 1st

60 Days

(Mcfe/d)

(# of wells)

1st Qtr 2014 21 3,859 $6.2 6,231 (21) 6,326 (21)

2nd Qtr 2014 23 4,982 $6.3 6,276 (23) 6,281 (23)

3rd Qtr 2014 18 5,288 $6.3 5,852 (18) 6,054 (18)

4th Qtr 2014 26 5,333 $5.9 5,814 (26) 5,800 (26)

1st Qtr 2015 22 4,713 $5.8 6,791 (22) 6,772 (22)

2nd Qtr 2015 21 5,853 $6.7 6,039 (21) 6,095 (21)

3rd Qtr 2015 19 5,512 $5.5 4,989 (26) 5,154 (26)

4th Qtr 2015 38 5,405 $4.9 5,019 (31) 5,418 (31)

1st Qtr 2016 3 5,659 $5.5 4,462 (3) 4,472 (3)

2nd Qtr 2016 6 7,207 $6.5 7,492 (6) 7,501 (6)

3rd Qtr 2016 3 4,762 $4.7 15,535 (3) 14,569 (3)

4th Qtr 2016 12 6,075 $5.1 17,178 (12) 16,645 (12)

1st Qtr 2017 24 5,836 $5.6 14,624 (24) 13,816 (24)

2nd Qtr 2017 21 5,530 $5.1 12,659 (21) 12,230 (21)

3rd Qtr 2017 15 8,093 $7.2 15,673 (6) 17,907 (4)

35

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000

0 2 4 6 8 10 12 14 16 18

Daily

Rate

, M

cf/d

Months of Production

Susquehanna County

Previous Completion Design (199 Wells) Optimized Completion Design (54 Wells) 12 BCF EUR Curve

Northeast AppalachiaMaterially improved well performance

• Susquehanna County initial EUR increase of over 25% due to changes in

completion intensity and flowback methods

Impact of third-party gathering line

issues, which are expected to be

resolved in the second half of 2017

36

Northeast AppalachiaWell performance by county

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 365 730 1095 1460

Daily

Rate

, M

CF

/d

Days of Production

Bradford County Lycoming County Susquehanna County 8 BCF EUR Curve 10 BCF EUR Curve 12 BCF EUR Curve

Note: Excludes downtime and exploratory wellsSusquehanna County excludes wells with new completion design

Company Operated Drilled Wells(Utilizing Historical Completion Designs)

3737

Fayetteville

38

Fayetteville

10.9

7.96.7 6.2

6.8 7.3 7.0

10 11 12 13 14 15 16

$2.8 $2.8$2.5 $2.4

$2.6$2.8

$3.2

10 11 12 13 14 15 16

4,5284,836 4,819

5,356 5,4405,729 5,717

10 11 12 13 14 15 16

2016 PDP F&D of $1.14(1)

Days to Drill Well Cost ($MM)

Production (Bcf)

+26%

-36%

Operating Statistics

350

437486 486 494

465

375

10 11 12 13 14 15 16

Lateral Length (ft.)

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 (ft)

1st Qtr 2014 105 4,272 2,616 ( 105) 2,205 (105) 5,664

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) 1,834 (97) 5,547

1st Qtr 2015 99 4,424 2,412 ( 99) 1,904 (99) 5,875

2nd Qtr 2015 68 4,405 2,564 ( 68) 2,087 (68) 5,836

3rd Qtr 2015 50 3,886 2,106 ( 50) 1,748 (50) 5,407

4th Qtr 2015 43 4,277 2,520 ( 43) 2,105 (43) 5,663

1st Qtr 2016 9 6,586 2,719 ( 9) 2,351 (9) 5,496

2nd Qtr 2016 6 6,352 2,792 ( 6) 2,431 (6) 6,870

3rd Qtr 2016 6 6,836 3,371 ( 6) 3,381 (6) 6,853

4th Qtr 2016 22 4,045 1,996 ( 22) 1,984 (22) 5,547

1st Qtr 2017 12 5,838 4,085 ( 12) 3,489 (12) 6,858

2nd Qtr 2017 8 4,565 3,208 ( 8) 2,454 (8) 6,763

3rd Qtr 2017 3 4,744 5,447 ( 1) N/A 5,892

(1) See definition and reconciliation on page 53.

39

-

0.5

1.0

1.5

2.0

2.5

Bcf/

dFayetteville TakeawayHigh correlation to Henry Hub


• Information in table and graph assumes FERC approval of recently announced firm

transportation agreement with Texas Gas Transmission


• Volumetric Firm Transport Costs are usage based

Volumetric Firm Transport

Year

SWN Firm

Transport

(MMbtu/d)

Reservation

Rate per

MMbtu

Firm Sales

(MMbtu/d)

Rate per

MMbtu

Total Firm

Transport

(MMbtu/d)

Annual

WAVG Rate

per MMbtu

2017 1,883,333 $0.27 0 $0.00 1,883,333 $0.27

2018 1,300,000 $0.31 0 $0.00 1,300,000 $0.31

2019 1,300,000 $0.29 0 $0.00 1,300,000 $0.29

2020 1,283,333 $0.26 0 $0.00 1,283,333 $0.26

2021 550,000 $0.10 0 $0.00 550,000 $0.10

100% 100% 100% 100%

0%

20%

40%

60%

80%

100%

2017 2018 2019 2020

Sales Locations

Gulf Coast

40

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

0 100 200 300 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500

Days of Production

Mcf/d

6 Bcf Typecurve

Moorefield Wells

Moorefield Well performance

(1) Includes Moorefield wells on production as of September 30, 2017.

(1)

Normalized to 6,500’ CLAT

41

FayettevilleWell performance

(1) Data as of September 30, 2017. Excludes shut-in wells and wells with mechanical problems (113).

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

Fayetteville Wells Normalized to 5,300' CLAT

4242

Vertical Integration

43

Midstream

Gathered volumes at Sept 30, 2017 (Bcf/d) 1.4

Gathering lines at Sept 30, 2017 (Miles) 2,045

Compression at Sept 30, 2017 (Horsepower) 421,515

Fayetteville Shale Gathering

2016 Total volumes marketed (Bcfe) 1,062

YTD 2017 Total volumes marketed (Bcfe) 782

SWN Marketing

Results for the 9 months ended Sept 30, 2017

Marketing revenues ($MM) $2,173

Gas gathering revenues ($MM) $241

Marketing purchases ($MM) $2,141

Operating costs and expenses(1) ($MM) $144

Operating income ($MM) $129

(1) Includes $47 million in depreciation and amortization expenses.

44

Vertical integration provides competitive advantages

• Strategic and economic benefit that

lowers net well costs

• Provides improved operating efficiency

and flexibility

• Mitigates service cost inflation

• Drilling Services

– 7 state-of-the-art drilling rigs

• Reduce well cost by ~$50K per well

• Move ~1 days faster than peers(1)

• High horsepower mud pump package

• Hydraulic Fracturing

– Restarted in July 2017

– Total capacity of ~72,000 horsepower

• Sand Mine in Fayetteville

– Produces 30/70 and 100 mesh sized sand

(1) Based on internal estimates & analysis of public data.

4545

Other

46

An Industry Leader in Corporate Responsibility

Logistics

Advancing Leak Detection

Technology

Model

Regulatory

Framework

• Freshwater neutral – December 2016

• 3.2 billion gallons of water conservation

• Produced water reuse – 37% of total

• SWN methane emissions – 0.19%

• LDAR 98% of facilities in 2016

• Contractor safe driver training• $1.6 million charitable contributions

• 4,550 employee volunteer hours

• Supporting STEM education

• Eliminated 17,000 truck deliveries

• Reduced mileage – 376,000 miles

• Pipeline transport of water

• Participating in scientific studies

• Facilitating new technology

• Founding member ONE Future

• Supply chain target < 1%

• Recognized by EPA Methane

Challenge

• Reviewed 100% of chemicals used

for hydraulic fracturing in 2016

• Replaced 42 chemicals

• Partnership with EDF

• Model regulation for wellbore

integrity

47

Appalachia Takeaway CapacityImproving basis differentials as a result of pipeline infrastructure

Source: SWN internal analysis

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

BC

F/d

Existing Takeaway DTI Leidy South EQT Mountain Valley Pipeline TCO MXP/ GXP Access South

DTI Atlantic Coast Pipeline CGT Rayne Xpress TCO WB Xpress TETCO Gulf Market Expansion II Rover Pipeline

Transco Atlantic Sunrise NF Northern Access Penn East Constitution Nexus

• Over the next 4 years, executed transportation agreements will provide a pathway for

~16 BCF/d of production to leave the Appalachian region (NE and SW)

• ~1.5 BCF/d of new takeaway was placed in-service in late 2016 and early 2017

• Certificates were awarded and construction has commenced on ~3.5 BCF/d of

takeaway with expected in-service of late 2017

• From Q3 2018 and forward, transportation capacity of ~8 BCF/d will likely go in-service

and fill projected gas demand in the Gulf Coast, Mid Atlantic, and Southeast

48

U.S. Natural Gas Supply & Demand

12-Month Rolling Average

Source: EIA

17

18

19

20

21

22

23

24

25

26

27

28

29

Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17

TCF

Dry Prod Net Import Consume

49

Financial and Operational Summary

(1) Net cash flow and adjusted EBITDA are non-GAAP financial measures. See explanations and reconciliations on pages 50 and 52, respectively.

(2) Adjusted net income attributable to common stock and adjusted diluted EPS are non-GAAP financial measures. See explanations and reconciliations on page 51.

(3) Includes the impact of hedges.

(4) See explanation and reconciliation of PDP F&D on page 53.

2017 2016 2016 2015 2014

Revenues 2,394$ 1,752$ 2,436$ 3,133$ 4,038$

Adjusted EBITDA(1)902$ 479$ 721$ 1,471$ 2,343$

Adjusted Net Income Attributable to Common Stock(2)156$ (52)$ (7)$ 71$ 801$

Net Cash Flow(1)816$ 434$ 645$ 1,468$ 2,270$

Adjusted Diluted EPS(2)0.31$ (0.12)$ (0.01)$ 0.19$ 2.27$

Production (Bcfe) 658 673 875 976 768

Avg. Realized Gas Price ($/Mcf)(3)2.22$ 1.51$ 1.64$ 2.37$ 3.72$

Avg. Realized Oil Price ($/Bbl) 41.48$ 28.53$ 31.20$ 33.25$ 79.91$

Avg. Realized NGL Price ($/Bbl)(3)13.06$ 6.11$ 7.46$ 6.80$ 15.72$

E&P Metrics

Lease Operating Expense ($/Mcfe) 0.90$ 0.87$ 0.87$ 0.92$ 0.91$

General and Administrative Expense ($/Mcfe) 0.22$ 0.21$ 0.22$ 0.21$ 0.24$

Taxes, Other than Income ($/Mcfe) 0.10$ 0.09$ 0.10$ 0.10$ 0.11$

PDP Finding Cost ($/Mcfe)(4)0.75$ 0.88$ 1.23$

Year Ended December 31,

($ in millions, except per share amounts)($ in millions, except per share amounts)

9 Months Ended Sept 30,

50

Explanation and Reconciliation of Non-GAAP Financial Measures: Net Cash Flow

We define net cash flow as cash flow from operating activities adjusted for changes in operating assets and liabilities and

restructuring charges. Management presents this measure because (i) management uses it 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.

2017 Guidance

NYMEX - $3.25 Gas / $55.00 Oil

($ in millions)

Cash flow from operating activities:

Net cash provided by operating activities $1,075 - $1,125

Add back (deduct):

Change in operating assets and liabilities -

Net cash flow $1,075 - $1,125

2017 2016 2017 2016 2016 2015 2014

($ in millions)

Cash flow from operating activities:

Net cash provided by operating activities $211 $172 $789 $337 $498 $1,580 $2,335

Add back (deduct):

Change in operating assets and liabilities 37 - 27 50 99 (112) (65)

Restructuring charges - 1 - 47 48 - -

Net cash flow $248 $173 $816 $434 $645 $1,468 $2,270

12 Months Ended December 31, 3 Months Ended Sept 30,

($ in millions)


($ in millions)

51

Explanation and Reconciliation of Non-GAAP Financial Measures: Adjusted Net Income Attributable to Common Stock

Additional non-GAAP financial measures we may present from time to time are adjusted net income attributable to common stock and adjusted diluted earnings per share

attributable to Southwestern Energy stockholders, both of which exclude certain charges or amounts shown in the tables below. 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.

(1) 2017, 2016 and 2015 primarily relate to the exclusion of certain discrete tax adjustments due to an increase to the valuation allowance against the Company’s deferred tax assets.

(2) 2014 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.

(3) 2016 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.

($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share)

Net income (loss) attributable to common stock 43$ 0.09$ (735)$ (1.52)$ 548$ 1.10$ (2,514)$ (6.02)$

Add back (deduct):

Participating securities - mandatory convertible preferred stock 2$ 0.00$ (2)$ (0.00)$ 59$ 0.12$ -$ -$

Impairment of natural gas and oil properties - - 817 1.69 - - 2,321 5.56

(Gain) Loss on certain derivatives (31) (0.06) (81) (0.17) (350) (0.70) 48 0.12

Adjustments due to inventory valuation and other - - (1) (0.00) (1) (0.00) 3 0.01

Gain on sale of assets, net - - - - (3) (0.01) (2) (0.01)

Restructuring and other one-time charges - - 2 0.01 - - 77 0.19

Legal settlements 5 0.01 - - 5 0.01 -

Loss on early debt extinguishment and other (3) 59 0.12 57 0.12 70 0.14 57 0.14

Adjustments due to discrete tax items (1,2) (37) (0.07) 256 0.53 (279) (0.56) 903 2.16

Tax impact on adjustments (12) (0.03) (301) (0.63) 107 0.21 (945) (2.27)

Adjusted net income (loss) attributable to common stock 29$ 0.06$ 12$ 0.03$ 156$ 0.31$ (52)$ (0.12)$

($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share)

Net income (loss) attributable to common stock (2,751)$ (6.32)$ (4,662)$ (12.25)$ 924$ 2.62$

Add back (deduct):

Participating securities - mandatory convertible preferred stock -$ -$ (13)$ (0.03)$ -$ -$

Impairment of natural gas and oil properties 2,321 5.33 6,950 18.26 - -

(Gain) Loss on certain derivatives 373 0.86 155 0.41 (130) (0.37)

Adjustments due to inventory valuation 3 0.01 32 0.08 - -

Gain on sale of assets, net (3) (0.00) (283) (0.74) - -

Transaction costs - - 54 0.14 5 0.01

Restructuring and other one-time charges 89 0.20 2 0.01 - -

Loss on early debt extinguishment and other (3) 57 0.13 - - - -

Adjustments due to discrete tax items (1,2) 978 2.25 483 1.27 (46) (0.13)

Tax impact on adjustments (1,074) (2.47) (2,647) (6.96) 48 0.14

Adjusted net income (loss) attributable to common stock (7)$ (0.01)$ 71$ 0.19$ 801$ 2.27$

20162017 2016

12 Months Ended December 31,

2016 2015 2014

2017

3 Months Ended Sept 30, 9 Months Ended Sept 30,

52

Explanation and Reconciliation of Non-GAAP Financial Measures: Adjusted EBITDA

EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Adjusted EBITDA is defined as EBITDA less gains (losses) on sale

of assets and gains (losses) on derivatives (net of settlement) plus write-down of inventory, non-cash stock based compensation, restructuring charges and loss on debt

extinguishment. 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 GAAP 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.

(1) Includes impact from full cost ceiling test impairment of our natural gas and oil properties.

(1)

2017 2016(1) 2016(1) 2015(1) 2014

Net income (loss) $712 ($2,433) ($2,643) ($4,556) $924

Add back (deduct):

Net interest expense 97 57 88 56 59

Provision (benefit) for income taxes (14) (20) (29) (2,005) 525

Depreciation, depletion and amortization (1) 364 2,670 2,757 8,041 942

Gain on sale of assets, net (3) (2) (3) (283) -

Non-cash stock based compensation 22 28 35 31 23

Adjustments due to inventory valuation and other (1) 3 3 32 -

Restructuring and other one-time charges - 77 89 - -

Legal settlements 5 - - - -

Loss on debt extinguishment 70 51 51 - -

(Gain) loss on derivatives excluding derivatives, settled (350) 48 373 155 (130)

Adjusted EBITDA $902 $479 $721 $1,471 $2,343


($ in millions)($ in millions)

12 Months Ended December 31,

53

Explanation and Reconciliation: Proved Developed Finding and Development Costs

Proved developed (PDP) finding and development (F&D) costs are computed here by dividing exploration and development capital costs

incurred, excluding capitalized interest and expenses, for the indicated period by PDP reserve additions and proved undeveloped (PUD)

conversions for that same period. At times, adjustments are made to this calculation in order to improve usefulness for investors. The methods

used by Southwestern to calculate its PDP F&D costs may differ significantly from methods used by other companies to compute similar

measures and, as a result, Southwestern’s PDP F&D costs may not be comparable to similar measures provided by other companies.

(1)

(1) Excludes capitalized interest and expenses to adjust for the impacts of the full cost accounting method.

NE App SW App Fay 2016 2015 2014 2013

Total PDP Adds (Bcfe):

New PDP Adds 81 157 19 257 416 531 945

PUD Conversions 181 0 39 220 1,044 790 312

Total PDP Adds 262 157 58 477 1,460 1,321 1,257

Costs Incurred ($MMs):

Proved Property Acquisition Costs $0 $0 $0 $0 $81 $1,455 $1

Unproved Property Acquisition Costs 11 149 3 171 692 3,934 168

Exploration Costs 8 8 1 17 50 232 192

Development Costs 178 133 86 433 1,417 1,600 1,662

Capitalized Costs Incurred $197 $290 $90 $621 $2,240 $7,221 $2,023

Subtract:

Proved Property Acquisition Costs $0 $0 $0 $0 ($81) ($1,455) ($1)

Unproved Property Acquisition Costs (11) (149) (3) (171) (692) (3,934) (168)

Capitalized Interest and Expense(1) Associated

with Development and Exploration (31) (28) (21) (91) (187) (206) (182)

PDP Costs Incurred $155 $113 $66 $359 $1,280 $1,626 $1,672

PDP F&D $0.59 $0.72 $1.14 $0.75 $0.88 $1.23 $1.33

12 Months Ended December 31, 2016 12 Months Ended December 31,

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