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March 2018 Investor Update
Repositioning to Win
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
Julian Bott
Executive Vice President &
Chief Financial Officer
Phone: (832) 796-6161
Fax: (832) 796-4820
Paige Penchas
Vice President, Investor Relations
Phone: (832) 796-4068
Fax: (832) 796-4820
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 March 1, 2018 unless otherwise indicated.
3
Building for Tomorrow
• Pursue strategic alternatives for Fayetteville Shale
– Further de-lever balance sheet
– Expand financial flexibility
• Accelerate value from Appalachia assets
– Target liquids growth in Southwest Appalachia to enhance returns
• Improve capital efficiency and expand margins
• Identify and implement structural, process and organizational changes
to further reduce costs
• Expand breadth and depth of high return inventory at lower commodity
prices
4
• Actively pursue strategic
alternatives for the Fayetteville
Shale E&P and related
midstream gathering assets
• Further strengthen the balance
sheet
• Accelerate value from the
Company’s Appalachia assets
• Identify and implement cost
reductions
• Enhance financial flexibility and
position long-term performance
• Expanded margins and
improved capital efficiency
• Improved well productivity
through technical and
operational enhancements
• Proactive commodity risk
management program
• Renegotiated transportation
and processing agreements
enhancing margins
• Extended debt maturities;
improved liquidity profile
Executing on Our Strategy
Stabilize
Executing a 3-phase strategy to maximize shareholder value
Reposition to Compete and Win
• Strengthened the balance sheet
• Reduced debt and improved liquidity through non-core asset monetization and equity offering
• Amended and extended bank facilities adding duration and preserving operational flexibility
• Restructured organization in 2016 to reduce costs by ~$175 million
• Committed to investing within cash flow through returns driven capital allocation
Optimize and Increase Value
5
Our Formula Drives Our Success
• Strengthen 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
• Low decline, cash flow generating Fayetteville asset
• High degree of operational control and flexibility
• Identified upside present throughout portfolio
Premier quality, large scale assets
• Well enhancements and cost optimization, improving
returns and expanding inventory
• Low cost, high margin culture
• Value creation across natural gas & NGL liquids value
chain
Increasing capital efficiency
and margin expansion
• Superior reservoir performance
• Maximizing resource access through operational efficiency
and execution
• Optimizing completion techniques to enhance well
productivity and economics
Leading technology, operating
and commercial capabilities
6
Asset Overview
Reserves & Production2017 Production: 897 Bcfe
12/31/2017 Reserves: 14.8 Tcfe
AR
WV
PANortheast Appalachia
2017 Reserves – 4.1 Tcf (28%)
2017 Production – 395 Bcf (44%)
Net acres – 191,226 (12/31/17)
Southwest Appalachia
2017 Reserves – 7.0 Tcfe (47%)
2017 Production – 183 Bcfe (20%)
Net acres – 290,291 (12/31/17)
Fayetteville Shale
2017 Reserves – 3.7 Tcf (25%)
2017 Production – 316 Bcf (35%)
Net acres – 917,842 (12/31/17)
Gross Drilling Locations Remaining for
Assumed NYMEX Gas Prices(1,2)
$2.75 $3.00 $3.25 $3.50
SW Appalachia 1,575 2,275 2,625 3,700
NE Appalachia 225 300 350 425
Fayetteville 350 850 1,125 1,625
SWN Total 2,150 3,425 4,100 5,750
(1) Assumes 10% return
(2) Based on $50 oil price
7
Appalachia65%
Fay35%
2017 Highlights
• Delivered on commitment to invest within net cash flow(1)
• Production of 897 Bcfe and total proved reserves of ~14.8 Tcfe
• Optimized completion techniques resulting in increased type curves and
improving economics in the Appalachian Basin
• Enhanced margins through renegotiation of transportation and processing
contracts and expansion of low-cost firm pipeline capacity portfolio
• Extended maturity profile with no significant bond maturities before 2022
(1) Supplemented by the remaining $200 million from the 2016 equity offering as previously disclosed
897Bcfe
$0
$500
$1,000
$1,500
$2,000
18 19 20 21 22 23 24 25 26 27
$ M
Ms
No significant
maturities until 2022
Bond Maturity Schedule2017 Production
8
2017 Proved Reserves Growth
Year-end Reserve Profile (Tcfe)
Reserve Growth by Commodity Pre-tax PV10 ($B)
2017 Proved Reserves
• Proved reserves - 14.8 Tcfe (181% increase)
– 75% natural gas and 25% liquids
– 46% proved undeveloped
• Appalachia reserves - 11.1 Tcfe (393% increase)
– Appalachia represents 75% of total reserves
• Pre-tax PV-10 value - $5.8 billion (247% increase)
– Appalachia represents 66% of total value
• Reserve life index – 16.5 years (175% increase)2.3
11.1
3.0
3.7
5.3
14.8
2016 2017
Appalachia Fayetteville
$0.4
$3.8
$1.3
$2.0
$1.7
$5.8
2016 2017
Appalachia Fayetteville
75%
25%
Natural Gas Liquids
93%
7%
2017
14.8 Tcfe
2016
5.3 Tcfe
9
2018 Key Objectives
• Expand value
– Capture additional value from higher margin natural gas liquids
– Expansion of economic inventory
– Reshape cost structure
– Further enhance well productivity
• Increase capital efficiency
• Accelerate activity in the high returns Appalachian basin
• Reposition portfolio
• Improve balance sheet
Appalachia71%
Other10%
CI&E19%
2018 Capital(1) 2018 Production(1) 2018 EBITDA(1,2)
Appalachia72%
Fay28%
Appalachia64%
Fay17%
Midstream14%
$1.25 B -
$1.35 B
930 – 965
Bcfe
$1.15 B -
$1.25 B
(1) Excludes any impact from the strategic actions announced February 8, 2018
(2) EBITDA is a non-GAAP financial measure. See explanations and reconciliations on SWN.com under “Latest Guidance – February 2018”.
10
Doing More with Less in 2018
(1) Based on an average swap or purchased put strike price as of February 2, 2018. See slide 26 for more details.
(2) Based on guidance issued in February 2018
• Fully funded 2018 capital program at $2.85/$60.00 with flexibility to adjust investment levels
and align with commodity prices
• Hedges on ~69% of projected 2018 natural gas volumes @ $2.97 per mcf (1)
• 2018 cash flow = $1.15 B to $1.25 B = 2018 capital investment
Drilling & completions $775 - $815
Land, seismic & other E&P$80 - $95
Water project$65 - $75
Midstream & corporate$15 - $30
Capitalized interest & expense
$215 - $235
2018
Capital
Investments(2)
$1.15 - $1.25B
$ in millions
Cash Flow Neutral with Changing Commodity Prices
Higher cash flow
Higher production
Higher returns
Lower gas price
Less D&C activity
Less capital
Improving capital efficiency
11
$0.00
$0.20
$0.40
$0.60
$0.80
$1.00
$1.20
$1.40
2014 2015 2016 2017 Fay NE App SW App Rich
SW AppLean
$1.23
$0.88$0.75 $0.72
$0.90
$0.43 $0.49$0.28
PD
F&
D(1
)
(1) See explanation and reconciliation of proved developed (PD) F&D on page 60.
(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 2018 guidance:
(3) For more information on SW App Rich and Lean wells, see slides 35 and 36.
• Deliberate capital allocation to Appalachia driving down PD F&D costs
• Optimized drilling and completion designs increasing EUR’s throughout Appalachia acreage
• Vertical integration and improved cycle times reducing costs
Increasing Capital EfficiencyImproving PD F&D Costs
Historical PD F&D Results PD F&D of Development Opportunities(2)
Estimates Capital EUR CLAT
Fayetteville $2.7 MM 3 Bcf 5,300’
NE App $6.0 MM 14 Bcf 6,500’
SW App Rich(3) $7.9 MM 16 Bcfe 7,500’
SW App Lean(3) $7.9 MM 28 Bcfe 7,500’
(3) (3)
12
412480
557
86
98
127
498
578
684
16 17 18
Gas Liquids
Appalachia Growth Story
$165
$675
$835
16 17 18
Appalachia Production GrowthAppalachia EBITDA Growth
• Capable of self-funding future growth
• Investment flexibility between wet and dry gas
• Production to grow ~18% (assuming midpoints) over 2017 from only $770MM
in drilling and completions capital
– 30% increase in Southwest Appalachia production
– Northeast Appalachia transportation portfolio structured to capture materially improving basis
differentials without significant increases in transportation costs
NYMEX $2.46/$43 $3.11/$51 $2.85/$60
(1) Based on guidance issued in February 2018 assuming a $2.85 NYMEX gas price and $60.00 oil price. Production based on midpoint of guidance.
(1)(1)
13
Southwest AppalachiaCore position in premier play targeting stacked pays
• 2018 plan focusing on wet gas window of the
panhandle to capitalize on improving liquids pricing
– 875 Marcellus rich and lean gas locations
economic below $3.00/$50 NYMEX
• Targeting gross exit rate production growth of over
30% in 2018, compared to 2017
• Expect margins to improve by over 10% based on strip
pricing due to increased liquids focus and reduced
processing rates
• Company operated water infrastructure expected to
reduce well costs by $500K per well beginning in late
2018
• Each $2.50/Bbl increase in NGL price reduces
breakeven gas price by ~$0.50/Mcf
Operational and technical excellence
driving inventory and margin expansion
14
$12.08
$17.98
$27.91
$39.38
4Q 16 4Q 17 4Q 16 4Q 17
Southwest AppalachiaIncreasing NGL realizations driving economics in SW Appalachia
60%25%
10%
5%
Ethane Propane Butane Other
Increasing NGL RealizationsNGL Composition
57%
of WTI
71%
of WTI
32%
of WTI
25%
of WTI
Total NGL Realizations
(after transport costs) C3+ Realizations
(after transport costs)
• Realized over 90% increase in NGL pricing in 2017 compared to 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 approximately $50MM per year
• Each $2.50/Bbl increase in NGL price reduces breakeven gas price by ~$0.50/Mcf
15
Southwest AppalachiaA look to the future
• Southwest Appalachia provides future liquids rich production and cash flow growth
• Capable of doubling production over next 4 years assuming only $500 million per
year in capital investments(1,2)
• Vertical integration allows flexibility to move activity within assets rapidly
-
200
400
600
800
1,000
1,200
1,400
2015 2016 2017 2018 2019 2020 2021
Net
3-P
hase E
xit R
ate
(M
Mcfe
/d)
(1) Assumes $500 million a year capital investments excluding CI&E. Capital includes $85 million in non D&C capital. Actual budget depends on various
factors including prices and projected cash flows.
(2) Assumes 2/3 rich and 1/3 lean gas wells
16
Northeast AppalachiaDelivering value now and in the future
• Gross operated production of approximately 1,446 MMcf/d (1,218 MMcf/d net) as of Dec 2017
• Record gross operated production rate in 4Q 2017, an increase of ~32% compared to 4Q 2016
• Leading transportation portfolio with advantaged basis differential and sustained low cost
• Expected 2018 free cash flow with margins improving despite decreasing commodity prices(1,2)
• Driving improved productivity though enhanced completion and flowback methods across the play
• Successful delineation of ~30,000 net acres in Tioga area; initiating development drilling
SWN Acreage
(1) Free cash flow is calculated as cash flow from operations less capital investments
(2) Based on 2018 NYMEX gas price futures as of March 1, 2018
17
Northeast AppalachiaGenerating Free Cash Flow
• 2018 expected to be an inflection year in Northeast Appalachia
– Basis improvement of ~$0.25/Mcf without significant transportation cost increases
– Free cash flow(1) generation of ~$150 million with ~13% increase in production
– Demonstrating repeated performance uplift as a result of enhanced completions
-$100
$0
$100
$200
16 17 18
$ in
mill
ion
s
Free Cash Flow Generation
(1) Free cash flow is calculated as cash flow from operations less capital investments. Based on February 8, 2018 guidance.
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
0 100 200 300 400 500
Avera
ge C
um
ula
tive P
roductio
n p
er
Well
(MM
cf)
Days of Production
Optimized Operational Design (73 Wells)
Previous Operational Design (199 Wells)
Susquehanna County Cumulative Production
18
FayettevilleCore position with material production, cash flows and low risk inventory
SWN Acreage
• Gross operated production was 1,170 MMcf/d (771 MMcf/d net) as of December 2017
• Pursuing strategic alternatives for the Fayetteville Shale E&P and related midstream gathering assets
• Significant low risk future development inventory of approximately 1,700 locations
• Large concentrated position in the core of the Fayetteville Shale play
• Material low decline production with significant cash flow
• Close proximity to growing Gulf Coast demand and access to LNG export facilities with low cost
transportation secured through 2030
• Unlocked additional future value in the Fayetteville area with positive Moorefield delineation efforts
• Further testing in 2018 to illustrate the extensive potential for redevelopment opportunities
19
FayettevilleLow decline asset with significant upside
• Applied big data analytics to 4,000+ Fayetteville wells to define optimal well design
• Drilled first redevelopment well that resulted in a ~40% improvement in initial
production rates over historical wells validating data analytics model
• SWN has the lowest production base decline of peers due to the influence of later life
shallower declining Fayetteville
0
100
200
300
400
500
600
700
800
900
1,000
0 30 61 91 122 152 182 213 243 274 304 334 365
Avera
ge C
um
ula
tive P
roduction p
er
well
(MM
cf)
Days on Production
Enhanced Completion Design Historical Completion Design
New Completion Design EUR: 0.88 Bcf/1000'Previous Completion Design EUR: 0.64 Bcf/1000'
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)
(1) Source: RSEG report from September 2017 (Peers include Antero, Cabot, Chesapeake, Consol, EQT, Eclipse, RICE and Range)
Base Decline by Operator(1)Average Cumulative Production per Well
20
Repositioning to Win
• Rigorous financial discipline
• Proactive risk management
• Returns-focused 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
2121
Appendix
22
Corporate Governance Snapshot
• Strong governance practices
– Independence
• Independent oversight to serve the long-term interests of Southwestern Energy and our shareholders
• 9 out of 10 directors determined by Board to be independent
– Tenure balance
• Directors offer a balance of experience and fresh perspectives
– Added 3 new directors in 2017 – all former CEOs of publicly traded companies
• Average tenure of less than 5 years
– Culture
• Disciplined decision-making
• Long-term outlook
• Focus on company risks
• Difficult questions directed to executive leadership and directors
• Practices for increasing Board diversity
• Added organizational capacity and capability with new members of leadership team
– EVP, Chief Operating Officer
• Experienced operational executive
– EVP Corporate Development
• Extensive experience advising companies on strategy, corporate development and capital allocation
– EVP, Chief Financial Officer
• Diverse financial experience across the oil and gas industry
23
Strategy Delivering ResultsRecent Highlights
Improving
Capital
Efficiency
Recent
Highlights
Well Results
• Announced initiative to actively pursue strategic alternatives for the Fayetteville Shale E&P
and related midstream gathering assets
• Total net production of 239 Bcfe, including 162 Bcfe from the Appalachian Basin, up 18% and
41%, compared to 4Q 2016, respectively
• Realized C3+ NGL prices of $39.38 per barrel, or 71% of WTI (net of transportation costs), in
4Q 2017, up 41% compared to 4Q 2016
• Increased year-end 2017 reserves to 14.8 Tcfe, including 11.1 Tcfe from the Appalachian
Basin, up 181% and 393%, compared to year-end 2016, respectively
• Added to 2018 hedge position which now has ~566 Bcf hedged at an average floor price of
approximately $2.97/Mcf with upside potential on over 50% of hedged volumes(1)
• Expanded the Company’s prospective rich gas footprint by placing its northernmost pad to sales
in Brooke County, West Virginia. The productivity from these wells continues to improve capital
efficiency and returns with average F&D costs of $0.50 per Mcfe and a break-even gas price of
less than $1.00 with oil prices of approximately $55 per Bbl
• Placed two wells to sales in eastern Susquehanna County, with an average lateral length of over
9,600 feet, delivering a Susquehanna County company record average IP rate of over 34 MMcf
per day per well
• 2017 proved developed (PDP) F&D improved to $0.72 per Mcfe, a 4% improvement versus 2016
• Improved capital efficiency demonstrated by investing almost $100 million less in 2018 drilling and
completion activities while delivering both higher value and production growth versus the 2017
program
• Southwest Appalachia increased stage density and sand loading by 20% and 14%, respectively, in
2017 and increased its average horizontal lateral length by over 2,000 feet, or 41%, compared to
2016, which resulted in higher well productivity and increasing well level returns
(1) Based on an average swap or purchased put strike price as of February 2, 2018
24
Rigorous Financial Discipline
Strengthen the balance sheet• No significant near-term maturities
• Strong liquidity position of approximately $1.7B(1)
• Targeting long-term net debt to EBITDA of <2.0x
Invest within cash flow• Fully funded 2018 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
25
$0
$500
$1,000
$1,500
$2,000
Cash 2020
$M
Ms
2…Secured term loan
Strengthen the Balance SheetDebt Maturity Schedule
• Cash balance and undrawn revolver anchors liquidity position of approximately $1.7B(1)
• Extended maturity profile with no significant bond maturities before 2022
• Created additional financial flexibility through consent solicitation – conforms secured debt capacity under
the Company’s 2022 and 2025 notes to all other outstanding indentures
$0
$500
$1,000
$1,500
$2,000
2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027
$ M
Ms
No significant
maturities until 2022
(1) Excludes outstanding letters of credit
(2) Assumes 90% of 2020 notes retired or extended beyond 2020 prior to October 2019; otherwise, facility matures in 2019. As of December 31, 2017, the Company has successfully retired or
extended 89% of the 2020 notes.
(2)
Cash Balance vs Secured Term Loan Bond Maturity Schedule
26
$3.02
$2.96 $2.96
$3.00
$3.00 $3.00 $3.00 $3.00
$2.97 x $3.56
$2.90 x $3.27
$2.90 x $3.27
$2.39 x $2.97 x $3.41
$2.40 x $2.97 x $3.37
$2.40 x $2.97 x $3.37 $2.40 x
$2.97 x $3.37
$2.48 x $2.95 x $3.33 $2.48 x
$2.93 x $3.30
$2.48 x $2.93 x $3.30
$2.49 x $2.95 x $3.31
133
147 149
138
67
50 50 48
0
20
40
60
80
100
120
140
160
180
200
Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19
Vo
lum
es
He
dg
ed
(B
cf)
Swaps 2-Way Costless Collars 3-Way Costless Collars
HedgingProtecting balance sheet and targeted returns
(1) Based on an average swap or purchased put strike price as of February 2, 2018
(2) Amounts may not add due to rounding
Note: Please refer to our 2017 annual report on Form 10-K filed with the Securities and Exchange Commission for complete information on the Company’s commodity, basis and
interest rate protection
Hedge Summary(1)
2018 2019
Swaps 265 93
2-Way Collars 29 9
3-Way Collars 273 112
Total (Bcf)(2) 566 215
Avg. Floor Price $2.97 $2.96
2727
Southwest Appalachia
28
Southwest AppalachiaIncreasing Capital Efficiency
• Improved productivity
across the rich and lean
gas windows showing
increased production at
higher pressures
• Gen 2 completions
outperforming Gen 1
completions by ~30%
• 2018 wells are planned
with Gen 2 enhanced
completion designs
(1) 3-Phase Production normalized to 7,500’ CLAT
0
1,000
2,000
3,000
4,000
5,000
0 90 180 270 360 450 540
Cum
ula
tive P
roductio
n
(MM
cfe
)(1)
Producing Days
ALICE EDGE
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
0 90 180 270
Cum
ula
tive P
roductio
n
(MM
cfe
)(1)
Producing Days
WILLIAM RITCHEA
Completion
Design
Sand
Loading
(lb/ft)
Cluster
Spacing
(ft)
Previous Operator
Design1,000 – 1,300 45 - 110
Gen 1 2,000 65
Gen 2 2,000 – 5,000 35 - 65
ALICE EDGE
BROOKE COUNTY
PARKS
WILLIAM RITCHEA
0
500
1,000
1,500
2,000
2,500
3,000
0 30 60 90 120 150 180 210 240
Cum
ula
tive P
roductio
n
(MM
cfe
)(1)
Producing Days
BROOKE COUNTY
PARKS
29
Southwest AppalachiaRich vs Lean Economics
Liquids Rich Economics
Lean Gas Pricing ($/Mcfe)(1,2) Rich Gas Pricing ($/Mcfe)(1,2)
F&D ($/Mcfe)
• 2018 program targeting rich gas acreage with best
economics in portfolio
• 400 Marcellus rich gas locations economic at
$1.75/$50 NYMEX price
• Focus on value over production
• Uplift from liquids pricing more than offsets
higher F&D costs for rich gas locations
• Rich gas wells result in less production
compared to lean gas wells due to higher
condensate rates and lower gas rates
$0.26
$0.53
Lean Rich
$2.85 $2.85
$0.99$0.13
$3.75$2.86
$2.86
Unprocessed Processed
NYMEX BTU Premium NGLs Condensate
$9.60
$6.70
$2.85 $2.85
$0.59$0.10
$2.26$0.16
$0.16
Unprocessed Processed
NYMEX BTU Premium NGLs Condensate
$3.59
$5.37
(1) Pricing before basis differentials or transportation costs
(2) Based on $2.85 NYMEX, $60 WTI, and Mount Belvieu prices for Ethane $0.27, Propane $0.81, Iso-Butane $0.95, Normal Butane $0.94 and Pentanes $1.40
(3) For more information on SW App Rich and Lean wells see slides 35 and 36
EUR - 28 Bcfe
EUR - 16 Bcfe
30
$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
31
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)
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
7 RRC DMC Properties 10H -
Industry Wells in Progress
Progressing technical and economic
understanding of 15+ Tcf Utica resource
base
• Advancing delineation efforts to enhance
drilling economics
– 200 sq mile 3-D seismic acquisition
– OBO well participation
– Planned drilling activity
• Leveraging industry area activity to evaluate
performance and operational efficiencies
1
2
3
4
2
1
3
4
5
6
1
3
2
4
7
32
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)
(1) Source – Genscape and EIA data
(2) Source – OPIS & NYMEX ethane strip pricing information shown above is based on market quotes as of January 17, 2018
33
• Over the next 4 years, executed transportation agreements will provide a pathway for ~9 BCF/d of
production to leave the Southwest Appalachian region
• 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 January 29, 2018 and assumes sales locations percentages
($0.76)
($0.36)
($0.25)($0.28)
2017 2018 2019 2020
0
5
10
15
20
25
30
Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22
Bcf
/d
Future Industry Capacity
Existing Industry Capacity
Estimated Weighted Average Sales Differential
(excluding transportation)(1)Southwest Appalachia Transportation Capacity
34
Southwest Appalachia TakeawayIncreasing Gulf Coast market exposure
• No transportation fees associated with firm sales
• Assumes SWN Rover and TransCanada capacity in service in Q2 2018 and Q4 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)
39%54% 52% 52%
23%
35%33% 33%
27%
6% 10% 10%11%
5% 5% 5%
0%
20%
40%
60%
80%
100%
2018 2019 2020 2021
Sales Locations
Nymex
M2
TCO
Gulf
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
2018 310,000 $0.50 101,000 $0.00 411,000 $0.38
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
2021 777,000 $0.62 92,000 $0.00 869,000 $0.56
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
35
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
2015 30 6,978 $7.7 (16) 7,147 (30) 36 / 18 / 46 7,396 (30) 36 / 17 / 47
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
4th Qtr 2017 11 7,256 $8.8 (7) 8,646 (7) 34 / 18 / 48 9,305 (3) 34 / 18 / 48
(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.
37%
48%
15%
Production Mix
Gas
NGL
Oil
SWN Drilled & Completed Rich Gas Condensate
(Normalized to 7,500 ft lateral)
36
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
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) 51 / 9 / 40 5,977 (6) 52 / 8 / 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
4th Qtr 2017 - - - - - - -
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
52%47%
1%
Production Mix
Gas
NGL
Oil
SWN Drilled & Completed Lean Gas Condensate
(Normalized to 7,500 ft lateral)
3737
Northeast Appalachia
38
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
• Sales location percentages are based on fully utilized transportation and firm sales volumes
• Assumes all extensions exercised
Firm Sales
Transport Extension Options
Firm Transportation Capacity
Constitution
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
Bcf/
d
Constitution
Transport Extension Options
Firm Transportation Capacity
Firm Sales
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
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
2021 1,316,000 $0.32 35,000 $0.00 1,351,000 $0.31
11%18% 20% 20%
51%48% 47% 47%
31% 29% 28% 28%
7% 5% 5% 5%
0%
20%
40%
60%
80%
100%
2018 2019 2020 2021
Sales Locations
Gulf
M3
Dominion
Other
39
Northeast AppalachiaImproving basis differentials driving margin expansion
• SWN transportation portfolio structured to capture materially improving Northeast basis differentials
• Over the next 4 years, executed transportation agreements will provide a pathway for ~4 BCF/d of
production to leave the Northeast Appalachia region
(1) Basis information shown above is based on market quotes from ICE & Platts as of January 29, 2018 and assumes sales locations percentages
0
2
4
6
8
10
12
14
16
Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22
Bcf/
d
Existing Industry Capacity
Future Industry
Capacity
Estimated Weighted Average Sales Differential
(excluding transportation)(1)Northeast Appalachia Transportation Capacity
($0.60)
($0.27)($0.29) ($0.30)
2017 2018 2019 2020
40
Northeast AppalachiaContinued improvement
12.9
10.2 10.09.0
10.1
13 14 15 16 17
$7.0
$6.1$5.4 $5.3
$5.9
13 14 15 16 17
4,982 4,752
5,403
6,142 6,185
13 14 15 16 17
-16%
Days to Drill Well Cost ($MM)
Production (Bcf)
+24%
-22%
151
254
360 350395
13 14 15 16 17
Lateral Length (ft)
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 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 6,034 $6.0 14,624 (24) 13,816 (24)
2nd Qtr 2017 21 5,530 $5.1 12,271 (21) 11,928 (21)
3rd Qtr 2017 15 8,007 $7.4 15,767 (15) 15,321 (15)
4th Qtr 2017 23 5,754 $5.4 16,906 (15) 16,181 (10)
+162%
41
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 50 100 150 200 250 300 350 400 450 500Avera
ge C
um
ula
tive P
roduction p
er
Well
(MM
cf)
Days of Production
Susquehanna County Cumulative Production
Optimized Operational Design (73 Wells) Previous Operational Design (199 Wells)
42
Northeast AppalachiaWell performance by area
0
5,000
10,000
15,000
20,000
25,000
0 100 200 300 400 500 600 700
Daily
Rate
(M
cf/
d)
Days of Production
Legacy Susquehanna & Bradford (73 Wells) Tioga Area (4 Wells) 10 BCF EUR Curve 15 BCF EUR Curve 20 BCF EUR Curve
* Tioga area represents the first full development pad
Normalized to 6,500’ CLAT
Impact of third-party gathering line issues,
which were resolved in late 2017
4343
Fayetteville
44
Fayetteville2017 activity focused on delineating Moorefield
6.26.8 7.3 7.0
11.7
13 14 15 16 17
$2.4 $2.6 $2.8$3.2
$4.2
13 14 15 16 17
5,356 5,4405,729 5,717
6,609
13 14 15 16 17
Days to Drill Well Cost ($MM)
Production (Bcf)
Operating Statistics
486 494465
375
316
13 14 15 16 17
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 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 3,630 ( 3) 3,275 (3) 5,892
4th Qtr 2017(2) 2 6,718 6,213 ( 1) NA 8,116
(1) Increase due to Moorefield delineation testing
(2) Excludes one delineation well that is shut-in for further analysis
(1)(1)
45
-
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
Bcf/
dFayetteville TakeawayHigh correlation to Henry Hub
Firm Transportation Capacity
• Sales location percentages are based on fully-utilized transportation and firm sales volumes
• 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
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%
2018 2019 2020 2021
Sales Locations
Gulf Coast
46
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 Type Curve
Moorefield Wells
Moorefield Well performance
(1) Includes 22 Moorefield wells on production as of December 31, 2017
(1)
Normalized to 6,500’ CLAT
47
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
2 Bcf Type Curve
3 Bcf Type Curve
4 Bcf Type Curve
Fayetteville Wells Normalized to 5,300' CLAT
FayettevilleHistorical well performance
(1) Data as of December 31, 2017. Excludes shut-in wells and wells with mechanical problems (89).
• SWN has production history in >4,000 wells from the
Fayetteville Shale in an expansive area with well-
understood rock properties, homogenous subsurface
• Significant opportunity for redevelopment of legacy
Fayetteville properties utilizing modern day drilling and
completion methods coupled with longer laterals to
optimize performance
• Field primarily developed on average of 5,300’ CLAT;
redevelopment opportunities will vary in application and
length, some of which approach 10,000’ CLAT
4848
Vertical Integration
49
Midstream
Gathered volumes at Dec 31, 2017 (Bcf/d)(1) 1.3
Gathering lines at Dec 31, 2017 (Miles) 2,045
Compression at Dec 31, 2017 (Horsepower) 377,070
Fayetteville Shale Gathering
2017 Total volumes marketed (Bcfe) 1,067
2018E Total volumes marketed (Bcfe) 1,000 – 1,025
SWN Marketing
(1) Based on December 30, 2017 due to weather event on December 31, 2017
(2) Includes $64 million in depreciation and amortization expenses
Results for the 12 months ended December 31, 2017
Marketing revenues ($MM) $2,867
Gas gathering revenues ($MM) $331
Marketing purchases ($MM) $2,824
Operating costs and expenses(2) ($MM) $197
Operating income ($MM) $183
50
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 costs
– 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 third-party
business, enhancing economics even
further
51
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 day faster than peers(1)
• High horsepower mud pump package
• Hydraulic Fracturing
– One frac spread currently operating in
Southwest Appalachia
– 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
5252
Other
53
An Industry Leader in Corporate Responsibility
Logistics
Advancing Methane
Detection & Policies
• Freshwater neutral – December 2016
• 3.2 billion gallons of water conservation
• Produced water reuse – 37% of total
• 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
• Company-wide Leak Detection and
Repair (LDAR) Programs
• Participating in scientific studies
• Facilitating new technology
• Supply chain target < 1%
• Recognized by EPA Methane
Challenge
• SWN Goal of ≤ 0.36%
• Reviewed 100% of chemicals used
for hydraulic fracturing since 2016
• Replaced 42 chemicals
• API Voluntary Methane Reduction
Program
• Focus on 3 key emission sources
• Gold Certification by IES
(Independent Energy Standards)
• 10 wells in PA / 10 wells in West
Virginia
54
Appalachia Takeaway CapacityImproving basis differentials as a result of pipeline infrastructure
Source: SWN internal analysis
15.0
20.0
25.0
30.0
35.0
40.0
Bcf
/d
Existing Industry Takeaway DTI Leidy South EQT Mountain Valley Pipeline TCO 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 TGP Broad Run
• Over the next 4 years, executed transportation agreements will provide a pathway for ~13 BCF/d of
production to leave the Appalachian region (NE and SW)
• ~3.4 Bcf/d of new takeaway was placed in service in late 2017
• Basis differentials in Appalachia are improving and are likely to continue improving
55
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 Production Net Import Consumed
56
Financial and Operational Summary
(1) Net cash flow and adjusted EBITDA are non-GAAP financial measures. See explanations and reconciliations on pages 57 and 59, respectively.
(2) Adjusted net income attributable to common stock and adjusted diluted EPS are non-GAAP financial measures. See explanations and reconciliations on page 58.
(3) Includes the impact of hedges.
(4) See explanation and reconciliation of PDP F&D on page 60.
2017 2016 2015
Revenues 3,203$ 2,436$ 3,133$
Adjusted EBITDA(1)1,247$ 721$ 1,471$
Adjusted Net Income (Loss) Attributable to Common Stock(2)219$ (7)$ 71$
Net Cash Flow(1)1,138$ 645$ 1,468$
Adjusted Diluted EPS(2)0.44$ (0.01)$ 0.19$
Production (Bcfe) 897 875 976
Avg. Realized Gas Price ($/Mcf)(3)2.19$ 1.64$ 2.37$
Avg. Realized Oil Price ($/Bbl) 43.12$ 31.20$ 33.25$
Avg. Realized NGL Price ($/Bbl)(3)14.48$ 7.46$ 6.80$
E&P Metrics
Lease Operating Expense ($/Mcfe) 0.90$ 0.87$ 0.92$
General and Administrative Expense ($/Mcfe) 0.22$ 0.22$ 0.21$
Taxes, Other than Income ($/Mcfe) 0.10$ 0.10$ 0.10$
PDP Finding Cost ($/Mcfe)(4)0.72$ 0.75$ 0.88$
Year Ended December 31,
($ in millions, except per share amounts)
57
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 2016 2017 2016 2015
($ in millions)
Cash flow from operating activities:
Net cash provided by operating activities $308 $161 $1,097 $498 $1,580
Add back (deduct):
Change in operating assets and liabilities 14 49 41 99 (112)
Restructuring charges - 1 - 48 -
Net cash flow $322 $211 $1,138 $645 $1,468
12 Months Ended December 31, 3 Months Ended Dec 31,
($ in millions)
58
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) 2016 includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt
which was included in other interest charges
(2) 2017, 2016 and 2015 primarily relate to the exclusion of certain discrete tax adjustments due to an increase to the valuation allowance against the Company’s deferred tax assets
($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share)
Net income (loss) attributable to common stock 267$ 0.53$ (237)$ (0.48)$ 815$ 1.63$ (2,751)$ (6.32)$ (4,662)$ (12.25)$
Add back (deduct):
Participating securities - mandatory convertible preferred stock 31$ 0.06$ (6)$ (0.01)$ 90$ 0.18$ -$ -$ (13)$ (0.03)$
Impairment of natural gas and oil properties - - - - - - 2,321 5.33 6,950 18.26
(Gain) Loss on certain derivatives (101) (0.20) 324 0.66 (451) (0.90) 373 0.86 155 0.41
Adjustments due to inventory valuation (1) (0.00) - - (2) (0.00) 3 0.01 32 0.08
Loss on foreign currency adjustment 6 0.01 - - 6 0.01 - - - -
Gain on sale of assets, net (1) (0.00) - - (4) (0.01) (3) (0.00) (283) (0.74)
Transaction costs - - - - - - - - 54 0.14
Restructuring and other one-time charges - - 12 0.02 - - 89 0.20 2 0.01
Legal settlements - - - - 5 0.01 - - - -
Loss on early debt extinguishment and other (1) 3 0.01 - - 73 0.15 57 0.13 - -
Adjustments due to discrete tax items (2) (176) (0.36) 74 0.15 (455) (0.91) 978 2.25 483 1.27
Tax impact on adjustments 35 0.07 (128) (0.26) 142 0.28 (1,074) (2.47) (2,647) (6.96)
Adjusted net income (loss) 63$ 0.12$ 39$ 0.08$ 219$ 0.44$ (7)$ (0.01)$ 71$ 0.19$
3 Months Ended December 31,
2016
12 Months Ended December 31,
2017 2016 20152017
59
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 net income with historical Adjusted
EBITDA.
(1) Includes impact from full cost ceiling test impairment of our natural gas and oil properties.
(1)
2017 2016(1) 2015(1)
Net income (loss) $1,046 ($2,643) ($4,556)
Add back (deduct):
Net interest expense 135 88 56
Provision (benefit) for income taxes (93) (29) (2,005)
Depreciation, depletion and amortization (1) 504 2,757 8,041
Gain on sale of assets, net (4) (3) (283)
Non-cash stock-based compensation 28 35 31
Adjustments due to inventory valuation and other (2) 3 32
Restructuring and other one-time charges - 89 -
Legal settlements 5 - -
Loss on foreign currency adjustment 6 - -
Loss on debt extinguishment 73 51 -
(Gain) loss on derivatives excluding derivatives, settled (451) 373 155
Adjusted EBITDA $1,247 $721 $1,471
($ in millions)
12 Months Ended December 31,
60
Explanation and Reconciliation: Proved Developed Finding and Development Costs
Proved developed (PD) 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 PD 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 PD F&D costs may differ significantly from methods used by other companies to compute similar
measures and, as a result, Southwestern’s PD 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
2017 2016 2015 2014
Total PD Adds (Bcfe):
New PD Adds 1,258 257 416 531
PUD Conversions 46 220 1,044 790
Total PD Adds 1,304 477 1,460 1,321
Costs Incurred ($MMs):
Proved Property Acquisition Costs $0 $0 $81 $1,455
Unproved Property Acquisition Costs 194 171 692 3,934
Exploration Costs 22 17 50 232
Development Costs 1,024 433 1,417 1,600
Capitalized Costs Incurred $1,240 $621 $2,240 $7,221
Subtract:
Proved Property Acquisition Costs $0 $0 ($81) ($1,455)
Unproved Property Acquisition Costs (194) (171) (692) (3,934)
Capitalized Interest and Expense(1) Associated
with Development and Exploration (103) (91) (187) (206)
PD Costs Incurred $943 $359 $1,280 $1,626
PD F&D $0.72 $0.75 $0.88 $1.23
12 Months Ended December 31,
