Investor Presentation...Investor Presentation 2 Forward Looking Statements i n v e s t o r _ r e l...

Investor Presentation 1

NYSE:SWNwww.swn.com

March 2020

Investor Presentation


Forward Looking Statements

[email protected]

Paige Penchas832.796.4068

Bernadette Butler832.796.6079

Brittany Raiford832.796.7906

Investor Relations Contacts

Forward-Looking StatementsThis presentation contains forward-looking statements. Forward-looking statements relate to future events and anticipated results of operations, business strategies, and other aspects of our operations or operating results. In many cases you can identify forward-looking statements by terminology such as “anticipate,” “intend,” “plan,” “project,” “estimate,” “continue,” “potential,” “should,” “could,” “may,” “will,” “objective,” “guidance,” “outlook,” “effort,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “forecast,” “target” or similar words. Statements may be forward looking even in the absence of these particular words. Where, in any forward-looking statement, the Company expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that such expectation or belief will result or be achieved. The actual results of operations can and will be affected by a variety of risks and other matters including, but not limited to, changes in commodity prices (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; the risks related to the discontinuation of LIBOR and/or other reference rates that may be introduced following the transition, including increased expenses and litigation and the effectiveness of interest rate hedge strategies; unexpected cost increases; potential liability for remedial actions under existing or future environmental regulations; failure or delay in obtaining necessary regulatory approvals; potential liability resulting from pending or future litigation; general domestic and international economic and political conditions; the impact of a prolonged federal, state or local government shutdown and threats not to increase the federal government’s debt limit; as well as changes in tax, environmental and other laws, including court rulings, 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. InvestorsThe 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.

Use of Non-GAAP InformationThis 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.

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SWN OverviewSWN is an independent energy company with operations focused across 460,000 net acres in the Appalachia Basin

Northeast AppalachiaNet Acres: 173,9942019 Proved Reserves: 4.8 Tcf2020E Production (1) : 1,265 MMcf/d

100% gas

Southwest AppalachiaNet Acres: 287,6932019 Proved Reserves: 7.9 Tcfe2020E Production (1) : 1,052 MMcfe/d

50% gas 41% NGL 9% oil

3

Resource Potential 53 Tcfe

Total Locations 4,630

2019 Proved Reserves– Natural Gas / Liquids

12.7 Tcfe68% / 32%

2019 Proved Reserve PV-10 $3.7B

2019 Production– 2019 Condensate Production– 2019 NGL Production

778 Bcfe12.9 MBbls/d64.7 MBbls/d

2020E Production (1)

– 2020E Condensate Production (1)

– 2020E NGL Production (1)

848 Bcfe15.9 MBbls/d71.2 MBbls/d

Gross Producing Wells 1,205

YE 2019 Net debt $2.2B

YE 2019 Net debt / EBITDA 2.3x

1) Net production based off of midpoint of guidance issued February 27, 2020.


Shareholder Returns Driven StrategyPosition SWN as a gas and gas liquids leader in Appalachia

– Capitalizing on strategic opportunities in an industry in transition

– Prioritize large, transformational and accretive acquisitions that provide significant synergies

– Leverage track record of successful integration and execution

Increasing Resilience & Relevance

– Maintain disciplined capital allocation

– Generate sustainable free cash flow

– Drive growth through development of organic and/or acquired Tier 1 assets

– Evaluate and pursue distribution of capital to shareholders

– Converting resource to reserves

– Sustain low leverage and further improve credit ratings

– Expand margins for increased profitability

– Invest in highest return projects to grow EBITDA

– Hedge to reduce commodity risk

– Opportunistically reduce debt

– Further enhance well performance

– Leverage innovative technology

– Accelerate capital and operational efficiencies

– Optimize commercial and marketing practices

– Preserve and expand differentiated culture of unwavering vigilance for HSE, strong governance and integrity

IncreaseScale

CreateSustainable Value

ProgressBest-In-Class Execution

ProtectFinancial Strength


2019 Highlights


1) 2018 includes only Marcellus wells to sales. 2019 includes all wells to sales. 2) Net cash flow and net debt to adjusted EBITDA are non-GAAP financial measures. See explanations and reconciliations on pages 33-36.3) Trailing 12 months EBITDA for 2018 excludes Fayetteville EBITDA of approximately $375MM generated prior to December 2018 divestiture.

$1,248$1,140

2018 2019

Capital Investment ($MM)

$2.57$2.42

2018 2019

Weighted Avg. Realized Price, incl. Hedges ($/Mcfe)

1.9x2.3x

2018 2019

Net Debt/Adj EBITDA (2,3)

$1,352

$913

2018 2019

Net Cash Flow ($MM) (2)

$0.19 $0.18

2018 2019

General & Administrative Expenses ($/Mcfe)

$1,131

$824

2018 2019

Well Cost ($/ft) (1)

$0.93 $0.92

2018 2019

Lease Operating Expenses ($/Mcfe)

778702

22%Liquids

Appalachia Production (Bcfe)

2018 2019

Natural Gas Liquids


2019 Achievements Driving Future Performance

– Doing more with less – 2020 capital 20% less than 2019 driven by capital efficiencies and cost reductions

– Operational execution – Reducing well costs an additional $100 per lateral foot in 2020 after a 27% reduction in 2019

– High value growth – Condensate production growing 25% in 2020; grew 38% in 2019

– Protecting cash flows – Robust hedging program protecting 83% of gas and 100% of crude production in 2020; $180 million settled hedging gains in 2019

– Continued cost focus – Removed $122 million of G&A and interest costs in 2019 with an additional $40 million reduction in 2020

– Relentless environmental stewardship – Continued low methane emissions and another year of freshwater neutrality, over 10 billion gallons of water returned to the environment


$0 $0$213

$0

$2,000

$892$639 $484

2020 2021 2022 2023 2024 2025 2026 2027

$34SWN Peer A Peer B Peer C Peer D Peer E

Credit Facility 2020 2021 2022 2023 2024

Top Tier Balance SheetSWN Debt Maturity Schedule ($MM) (1)

– $2 billion credit facility with $172 million in letters of credit and $34 million in borrowings at year-end 2019

– Leading 5-year maturity window with no significant maturities until 2025

– Net debt/EBITDA 2.3X at year-end 2019; goal of sustaining near-term competitive position

Differentiated 5 Year Debt Maturity Profile (2,3)

– $2.2 billion in senior notes outstanding with weighted average interest rate of 6.7%

– Repurchased $62 million and retired $52 million of senior notes in 2019

– Maintained ratings with Moody’s, S&P and Fitch

1) As of December 31, 2019. 2) Peers are AR, COG, CNX, EQT and RRC.3) Includes senior notes and amounts outstanding on credit facilities as of December 31, 2019.

No significant maturities until 2025

$0.2B

$0.9B

$1.6B

$2.4B $2.5B

Senior Notes Credit Facility Borrowings

$3.2B


Liquids Production

– 23% increase in 2019 liquids production compared to 2018 to 77.6 MBbls/d

– Continued investment in high margin liquids rich acreage in 2020

– Total liquids production expected to average 87.1 MBbls/d(1) in 2020

1) Liquids production based off of midpoint of guidance issued February 27, 2020.

NGL Production (MBbls/d)

54.062.3 60.4 64.2

71.8

2018 Q1 19 Q2 19 Q3 19 Q4 19

Condensate/Oil Production (MBbls/d)

Third largest liquids producer in Appalachia

5%

60%25%

10%

NGLComposition

Ethane

Butane

Propane

C5+

9.3 9.5 10.3

15.4 16.2

2018 Q1 19 Q2 19 Q3 19 Q4 19

Total Liquids Production (MBbls/d)

63.371.7 70.7

79.788.0

2018 Q1 19 Q2 19 Q3 19 Q4 19


– Highest condensate yield and production across 108,000 acres in Appalachia, resulting in a higher realized price per Mcfe

– Super rich drilling locations comprise 60% of 8 year + liquids-rich inventory (1)

Superior Condensate AcreageLargest in Appalachia Basin

Cumulative Condensate Production (2,4)Highest Condensate Yield Acreage (2)

1) Liquids inventory approximates 550 locations as of 12/31/19 and years of production is based on 2020 60-70 wells to sales guidance.2) Six month condensate yield from all horizontal producing Marcellus wells. Source: RS Energy and public data3) Assumes condensate price of $55/Bbl. 4) As of December 31, 2019 and normalized to a 10,000 ft lateral length. Source: RS Energy and public data

Illustrative Condensate Benefit

Condensate Yield(Bbl/MMcf)

Price Uplift(3)

($/Mcfe)

10 $0.3825 $0.8750 $1.5475 $2.07

100 $2.50125 $2.86


Peer Leading Condensate Producer

– Initial 6 month cumulative condensate production per well and average condensate yield highest among Appalachia peers(1)

– Daily condensate production in Q4 2019 highest among peers

– Higher condensate yield provides economic uplift and improves returns1) Peers with Appalachia liquids production are AR, CNX, EQT and RRC.2) Includes all Southwest Appalachia Marcellus wells to sales in 2017-2019. Production is normalized to a 10,000 ft lateral length. Source: RS Energy, public data 3) Condensate production for the quarter ended December 31, 2019 as reported.

Average Initial 6-month Condensate Yield (1)

38.5

0.7 0.86.3

10.2

SWN Peer A Peer B Peer C Peer D

Average Initial 6-month Cumulative Gross Condensate Production per Well (2)

43,493

1,734 1,765

12,09516,641

SWN Peer A Peer B Peer C Peer D

Q4 2019 Net Condensate Production per day (3)

16.2

0.52.0

8.810.5

SWN Peer A Peer B Peer C Peer DBbl/MMcf Cumulative Bbls MBbls per day


2018 2019 2020E Record

Delivering Top Tier Well Costs Today

– Successfully lowered average well costs on wells to sales by 27% in 2019 to $824 per lateral foot− Achieved $778 per lateral foot for wells spud and to sales in 2019

– Estimated to reduce well costs an additional 10% in 2020 to $730 per lateral foot – Increasing average lateral lengths on wells to sales by 20% to over 12,000 ft

− 24 ultra-long laterals expected to be drilled in 2020 (greater than 15,000 ft)

1) 2018 includes only Marcellus wells.2) Includes all wells to sales in 2019 (113 wells), average CLAT 10,014 ft.3) Includes all wells to sales in 2020, estimated to be 100 wells based on the midpoint of guidance provide February 27, 2020.4) Single well record in Northeast Appalachia, CLAT approximately 14,000 ft.

Well Costs per lateral Foot ($)

$824

$605$730

$1,131

(1) (2) (3) (4)

27%Decrease

10%Decrease

Lateral LengthCompletion Design

Water SystemsVertical Integration

Direct Sourced Sand

Lateral LengthCompletion Design

Operational EfficienciesVertical Integration


Vertical IntegrationCompetitive advantage delivering top quartile operational performance

Strategic and economic benefit derived from vertical integration− SWN-owned super-spec drilling rigs and frac

fleet− Mitigates services cost inflation and provides

operational flexibility− Maximizes drilling efficiencies of pad

development and optimizes longer laterals− Peer-leading completion execution, setting

performance standards for supplemental third party contracted services

− Water management infrastructure− Up to $800,000 per well savings in West Virginia

operations− 1.3 million truckloads eliminated across

Appalachia since 2010

12


Leading Operational ExecutionReducing costs, increasing returns and accelerating cash flow

Footage Drilled (ft/day)(1)

1,178 1,304 1,400

2,224

2018 2019 2020E SWN Record(4)

(3)

5.4

7.9

12.0

2018 2019 2020E SWN Record

Completed Stages (stages/day)(2)

7,40710,014

18,683

2018 2019 2020E SWN Record

Lateral Length (ft)27

20

12

26

3 31

2018 2019 2020E SWN Record

Southwest Appalachia Northeast Appalachia

Facilities Installation (days)

Note: All percentage improvements compare 2020E to 2018.1) Footage drilled is based on number of days from spud to rig release.2) Stages/day is pad average, calculated as: Total stages on pad / days on pad.

3) New Record achieved in Q4 2019.4) Excludes some delineation wells.

56%Decrease

Southwest App

50%Decrease

Northeast App

35%Increase

19%Increase

62%Increase

7.3

12,000


Appalachia Resource PotentialResource to Reserves

Resource Potential (Tcfe)

Resource BreakdownLower Marcellus 21 Tcfe 1,750

Upper Marcellus 4 Tcf 400

Upper Devonian 10 Tcfe 1,080

Utica / Point Pleasant 18 Tcf 1,400

Total 53 Tcfe 4,630 locations

2017 2018 2019Lower Marcellus Upper Marcellus Upper Devonian Utica

5342

53Converting resource to proved reserves through subsurface expertise, performance improvements and cost reductions

– Further progression of Upper Devonian and Upper Marcellus

– Continuation of Utica / Point Pleasant learning with minimal capital commitment

– 4,630 total drilling locations

– 700 core locations economic at strip pricing– Increased economic inventory through

completion optimization and cost reductions

– Decrease in inventory year over year driven by increasing inventory lateral length and consumption


Appalachia Proved Reserves– Increased 2019 proved reserves 7% to 12.7 Tcfe

– Lowered Proved Developed (PD) F&D 24% to $0.53 per Mcfe

– Reserve life index of 16.4 years

– Replaced 203% of production with proved reserves in 2019

– 50% of reserves are proved developed

11.1

11.9

12.7

2017 2018 2019

Proved Reserves

by Product

32%

68%

Proved Reserves

by Division

38%

62%

NE Appalachia SW Appalachia Liquids Gas

Proved Reserves (Tcfe)

$0.80$0.72

$0.64$0.72 $0.70

$0.53

2017 2018 20193-Year Average PD F&D PD F&D

PD F&D ($/Mcfe)

1) 2017 excludes proved reserves associated with the Fayetteville Shale, divested in December 2018.

(1)


Appalachia NGL CapacitySWN has ample processing and fractionation capacity with no unused volume commitments

16

1) A portion of this is optioned at SWN’s election2) Sourced from Enkon Energy Advisors LLC

– Flow assurance today with capacity optionality in place for future growth

– In-basin capacity eliminates need to fractionate at Conway or Mt. Belvieu

– Diversified, flexible access across multiple processing and fractionation facilities

Regional FractionationCapacity (C2+)

1MM Bbl/d (2)

132,000 (1)

Regional Processing

Capacity10.5 Bcf/d (2)

1.6 (1)

SWN

16


NGL MarketsFlow reliability and marketing optionality provide flexibility to optimize pricing

17

Ethane– Firm transportation capacity on ATEX and

Mariner West with access to Mariner East 1– Ability to reject or recover ethane based on

marketing pricing

C3+– Access to Cornerstone, Teppco, Mariner

East 2, rail and truck– Mariner East 2 increases regional takeaway

with no SWN long-term commitment– Combination of direct and third-party

marketing to maximize value and mitigate risk

SWNSWN Liquids Marketing Options


Northeast AppalachiaGas Takeaway

18

Firm transportation portfolio delivers competitive advantage

– Low cost with multiple extension options– Premium market delivery to City Gate locations– Provides stability and diversity with multiple outlets

in greater Appalachia and Gulf Coast areas– Incremental capacity available for additional firm

sales

2020: 68%Greater AppalachiaDominionTGP 219TGP 313TGP 300L MarcellusTransco Leidy

2020: 5%Gulf CoastFGT Z3

2020: 27%City GateAlgonquinTetco M3TGP Z6 SouthTransco Z5Transco Z6 NNY

Differential to NYMEX

YearTotal Firm

Transportation (MMBtu/d)

Firm Sales (MMBtu/d)

Average Rate per MMBtu

Average Basis per MMBtu

2020 1,300,000 200,000 ($0.24) ($0.28)

Transportation (1) Location (2)

1) Committed volume and rate per MMBtu based on February 19, 2020 contracted takeaway and firm sales. Ability to release capacity or buy gas to fill excess transportation capacity. Pipelines include Millennium, Tennessee Gas Pipeline, Columbia Gas and Transco Pipeline.

2) Basis as of February 19, 2020. Includes transportation variable cost and excludes financial derivatives.


Southwest AppalachiaGas TakeawayDelivering natural gas to highest value markets

– Approximately 60% of gas delivered directly to Gulf Coast to meet growing LNG and industrial demand

– Expect to fill all current firm transportation by year-end 2020

– Incremental discounted capacity to Gulf Coast starting in 2021

19

2020: 9%M2 - AppalachiaDominionTetco M2Nymex Related

2020: 57%Gulf CoastCGT MainlineFGT Z2Sonat LATransco Z3Trunkline Z1A

2020: 34%TCO - AppalachiaTCO Pool

Differential to NYMEX

YearTotal Firm

Transportation(MMBtu/d)

Average Rate per MMBtu

Average Basis per MMBtu

2020 830,000 ($0.58) ($0.30)

Transportation (1) Location (2)

1) Committed volume and rate per MMBtu based on February 19, 2020 contracted takeaway. Not all 2020 volume commitment will be used. Ability to release capacity or buy gas to fill excess transportation capacity. Guidance for natural gas differentials includes all commitment costs. Pipelines include TETCO, Columbia Gas, MXP, GXP, and Rover.

2) Basis as of February 19, 2020. Includes transportation variable cost and excludes financial derivatives.


1.3 Million

Corporate ResponsibilityOperating responsibly is the Right Thing to do, and it’s good business. It improves our performance overall by reducing costs, minimizing risks and safeguarding employees and communities

Air Water Safety

77% Water Re-UseIn 2019, reused 77% of the produced water generated by operations (20,300 barrels per day)

SWN received the highest score among 30 of the largest oil and gas producers in 2019 Disclosing the Facts, released by shareholder advocacy group As You Sow and investment and advisory firm Boston Common Asset ManagementWebsite: disclosingthefacts.org

Rated #1

SWN reduced emissions by a cumulative 48 Bcf since 2006 – enough to power 724,000 homes per year

LOWER96%METHANE LEAK/LOSS RATE

THAN 2018 INDUSTRY AVERAGE

10+ BillionGallons of Fresh Water restored to the environment from conservation projects since 2014

Truck Trips EliminatedSWN has removed 1.3 million truckloads

of water off the roads since 2010 by installing water pipelines in Appalachia

REDUCTION IN TOTALRECORDABLE INCIDENTRATE(1) (TRIR) SINCE 2014

52%1) Includes hours worked by employees and contractors.


Building Long-Term Shareholder Value

– Rigorous, disciplined and returns-based capital allocation process

– Transitioning back to cash flow neutrality by the end of 2020

– Strong and flexible balance sheet; ample liquidity

– Diversified commodity risk management

– Right-sized flow assurance

– Improving costs, capital efficiency and operational execution

– Recognized environmental stewardship

– Pursuing long-term, accretive opportunities

21


Appendix



2020 Guidance(1)

As of February 27, 2020

PRODUCTION/CAPITAL GUIDANCE BY DIVISION(Bcfe) (in millions)

Northeast Appalachia 455 – 470 $235 – $260

Southwest Appalachia 375 – 395 $460 – $485

Other $25 – $35

Capitalized interest $85 – $95

Capitalized expense $55 – $65

TOTAL YEAR 830 – 865 $860 – $940

WELL COUNT SUMMARY

NE APP SW APP TOTAL YEAR

Drill 25 – 35 50 – 60 75 – 95

Complete 30 – 40 60 – 70 90 – 110

Wells to Sales 30 – 40 60 – 70 90 – 110

Ending DUC 0 – 10 5 – 15 5 – 25

PRODUCTION BY QUARTERQ1 Q2 Q3 Q4 TOTAL YEAR

Gas (Bcf) 150 – 156 152 – 158 170 – 177 170 – 177 642 – 668

Oil/Condensate (MBbls) 1,300 – 1,400 1,200 – 1,300 1,475 – 1,575 1,650 – 1,750 5,625 – 6,025

NGLs (MBbls) 6,000 – 6,275 6,150 – 6,425 6,600 – 6,875 6,750 – 7,025 25,500 – 26,600

Total (Bcfe) 194 – 202 196 – 205 219 – 228 221 – 230 830 – 865

Total (MMcfe/d) 2,132 – 2,220 2,154 – 2,253 2,380 – 2,478 2,402 – 2,500 2,268 – 2,363

E&P METRICSLease operating expense $0.92 – $0.97 per Mcfe

General & administrative $0.13 – $0.17 per Mcfe

Taxes, other than income $0.07 – $0.09 per Mcfe

Natural gas price differentials(2) $0.63 – $0.73 per Mcf

Oil price differentials(2) $9.50 – $11.50 per Bbl

NGL price realizations(2) 16 – 21% of WTI

Interest expense – net of capitalization(3) $80 – $90 MM

Income tax rate (~100% deferred) 23.5%

1) This guidance is based on $2.10 per MMBtu NYMEX Henry Hub and $50 per barrel WTI commodity price environment. 2) Price differentials include transportation costs. 3) Gross interest expense expected to be $165 – $185 MM. In 2019, gross interest expense was $174 MM.


2021

Q12020

Q22020

Q32020

Q42020

FY

Hedge Position

Swaps 2-Way Collars 3-Way Collars

0% 25% 50% 75% 100%

2020 Total Hedge % (1)

43% SWAPS 40% COLLARS 17%UNHEDGED

$2.88$2.75 x $3.03$2.34 x $2.73 x $3.07

$2.50$2.03 x $2.33 x $2.55

$2.50$1.96 x $2.26 x $2.47

$2.50$2.50 x $2.79$2.16 x $2.53 x $2.89

$2.54$2.50 x $2.83$2.18 x $2.49 x $2.84

68

94

109

28

119

38

512370

3017

264

Total

Q12020

108Total

Q22020

137Total

Q32020

157Total

Q42020

144Total

FY2021

312

Natural Gas Bcf, $/MMBtu

Swaps 2-Way Collars 3-Way Collars

0% 25% 50% 75% 100%

2020 Total Hedge % (1)

59% SWAPS 41% COLLARS

Total

1,332Total

1,275Total

1,598Total

1,697Total

836235261

731229315

866241491

1,032261404

2,328

1,445

$58.13$56.93 x $59.83$44.62 x $54.36 x $59.06

$58.06$56.98 x $59.86$45.06 x $54.86 x $59.46

$57.79$56.91 x $59.82$43.41 x $52.34 x $57.36

$57.44$56.76 x $59.75$43.71 x $52.85 x $57.78

$53.72$43.52 x $53.25 x $58.143,773

Crude MBbls, $/Bbl

1) Total hedge percentage based on the midpoint of guidance issued February 27, 2020. Hedge position as of February 25, 2020 including positions settled in 2020.


Hedge Position

Swaps

Total

Q12020

$8.83 ($0.21)1,873Total

Q22020

$8.61 ($0.20)2,028Total

Q32020

$8.64 ($0.21)2,045Total

Q42020

$8.62 ($0.21)2,153Total

FY2021

1,873

2,028

2,045

2,153

2,725 $7.48 ($0.18)2,725

Ethane MBbls, $/Bbl ($/gal)

Swaps 2-Way Collars

Total

Q12020 $24.08 ($0.57)

$25.20 x $29.40 ($0.60 x $0.70)1,237Total

Q22020 $24.03 ($0.57)

$25.20 x $29.40 ($0.60 x $0.70)1,259Total

Q32020 $23.97 ($0.57)

$25.20 x $29.40 ($0.60 x $0.70)1,304Total

Q42020 $23.95 ($0.57)

$25.20 x $29.40 ($0.60 x $0.70)1,312Total

FY2021

1,146

91

1,168

91

1,212

92

1,220

92

2,460 $21.77 ($0.52)2,460

Propane MBbls, $/Bbl ($/gal)

0% 25% 50% 75% 100%

2020 Total NGL Hedge % (1)

50% SWAPS 49% UNHEDGED

1% COLLARS

1) Total NGL hedge percentage based on the midpoint of NGL guidance issued February 27, 2020. Hedge position as of February 25, 2020 including positions settled in 2020.


0

3,000

6,000

9,000

12,000

15,000

18,000

0 100 200 300 400 500 600 700 800

Dai

ly R

ate

(Mcf

e/d)

Days Online

Gen 2 Completions (128 wells) 20 BCFe Type Curve 29 BCFe Type Curve 35 BCFe Type Curve

Southwest Appalachia Super Rich Gas Well Performance

1) Based on wells spud and to sales in 2019.

SWN Drilled & Completed Super Rich Gas Condensate (Normalized to 10,000 ft lateral)

ProductionMix

45% 39%

16%GAS OILNGL

2019 2019(1) 2020E

Average lateral length 10,604 ft 11,250 ft 13,238 ft

Well cost $8.8 MM $8.8 MM $9.5 MM

Cost per lateral foot $833 $783 $717

3-Phase EUR 22 Bcfe 24 Bcfe 37 Bcfe

EUR per 1,000 ft 2.1 Bcfe 2.1 Bcfe 2.7 Bcfe

Liquids 60% 60% 59%

F&D $0.39/Mcfe $0.37/Mcfe $0.26/Mcfe

Super Rich Wells (128 wells)


0

4,000

8,000

12,000

16,000

20,000

24,000

0 100 200 300 400 500 600 700 800

Dai

ly R

ate

(Mcf

e/d)

Days Online

Gen 2 Completions (20 wells) 36 BCFe Type Curve 42 BCFe Type Curve 48 BCFe Type Curve

Southwest Appalachia Rich Gas Well Performance

1) All wells spud and to sales in 2019.

SWN Drilled & Completed Rich Gas Condensate (Normalized to 10,000 ft lateral)

2019(1) 2020E

Average lateral length 11,806 ft 13,510 ft

Well cost $9.8 MM $10.8 MM

Cost per lateral foot $830 $799

3-Phase EUR 47 Bcfe 50 Bcfe

EUR per 1,000 ft 3.9 Bcfe 3.5 Bcfe

Liquids 40% 44%

F&D $0.21/Mcfe $0.22/Mcfe

ProductionMix

42% 56%

2%GAS OILNGL

Rich Wells (20 wells)


0

10,000

20,000

30,000

40,000

0 100 200 300 400 500 600 700 800

Dai

ly R

ate

(Mcf

/d)

Days Online

Susquehanna & Bradford (134 Wells) Tioga (27 Wells) 15 BCF EUR Curve 20 BCF EUR Curve 25 BCF EUR Curve

Northeast Appalachia Dry Gas Well Performance

1) Based on wells spud and to sales in 2019.

SWN Drilled & Completed Dry Gas (Normalized to 10,000 ft lateral)

2019 2019(1) 2020E

Average lateral length 9,029 ft 9,097 ft 10,079 ft

Well cost $7.3 MM $6.9 MM $7.2 MM

Cost per lateral foot $809 $762 $713

3-Phase EUR 17 Bcf 17 Bcf 19 Bcf

EUR per 1,000 ft 1.9 Bcf 1.9 Bcf 1.9 Bcf

F&D $0.43/Mcf $0.42/Mcf $0.38/Mcf


AirSWN maintains an ongoing, proactive commitment to methane and GHG emission reduction

96%LOWER

METHANE LEAK/LOSS RATE

THAN 2018 INDUSTRY AVERAGE

Engineering Design

Leak Detectionon 100% of wells

Collaboration with NGOs, government agencies and universities

Approach to minimizing GHG emissions

29Investor Presentation

SWN reduced emissions by a cumulative 48 Bcf since 2006 – enough to power 724,000 homes per year


Water ManagementWe are committed to Water Stewardship. For every gallon of freshwater used in Operations, that and more is returned to the environment through long-lasting conservation projects

10+BILLION

RESTORED TO THE ENVIRONMENTGALLONS OF FRESH WATER

OVER THE LAST 5 YEARS

77% Water ReuseIn 2019, reused 77% of the produced water generated by operations (20,300 barrels per day)

Freshwater conservation projects that will return 2.8 billion gallons of water to local watersheds annually

SWN received the highest score among 30 of the largest oil and gas producers in 2019 Disclosing the Facts, released by shareholder advocacy group As You Sow and investment and advisory firm Boston Common Asset ManagementWebsite: disclosingthefacts.org

Rated #1


GovernanceBoard of directors

− 7 out of 8 directors are independent− President and CEO – only non-independent− Average board member tenure is less than 5 years− 50% diverse (gender, nationality, ethnicity)

Best practices− Annual “say on pay” vote− Majority voting in director elections− Annual election of all directors− Proxy access− Ability to call special meetings− No supermajority voting standards− Regular shareholder engagement on compensation and other key issues

Management compensation− Independent directors approve compensation− Mix of awards weighted heavily on long-term equity based incentives

– Relative and absolute total shareholder return – Return on Average Capital Employed metric

− Stock ownership requirement− Compensation committee retains independent consultant− Annual performance metrics include environmental and safety performance

Social− Robust safety culture− Strong community engagement− Investment in human capital− Workplace respect

31


Financial and Operational Summary

1) Net cash flow and adjusted EBITDA are non-GAAP financial measures. See explanations and reconciliations on pages 33 and 35, respectively. 2) Adjusted net income attributable to common stock and adjusted diluted EPS are non-GAAP financial measures. See explanations and reconciliations on page 34.3) Includes the impact of derivatives.4) Excludes restructuring charges and other one-time items.

2019 2018 2017

Revenues 3,038$ 3,862$ 3,203$ Adjusted EBITDA (1) 973$ 1,484$ 1,247$ Adjusted Net Income Attributable to Common Stock (2) 328$ 590$ 219$ Net Cash Flow (1) 913$ 1,352$ 1,138$ Adjusted Diluted EPS (2) 0.61$ 1.02$ 0.44$

Production (Bcfe) 778 946 897 Realized Gas Price ($/Mcf) (3) 2.18$ 2.35$ 2.19$ Realized Oil Price ($/Bbl) (3) 49.56$ 56.07$ 43.12$ Realized NGL Price ($/Bbl) (3) 13.64$ 17.23$ 14.48$ Weighted Average Realized Price ($/Mcfe) (3) 2.42$ 2.57$ 2.29$

E&P MetricsLease Operating Expense ($/Mcfe) 0.92$ 0.93$ 0.90$ General and Administrative Expense ($/Mcfe) (4) 0.18$ 0.19$ 0.22$ Taxes, Other than Income ($/Mcfe) (4) 0.08$ 0.09$ 0.10$

Years Ended December 31,

($ in millions, except per share amounts)


Explanation and Reconciliation of Non-GAAP

We define net cash flow as cash flow from operating activities adjusted for changes in operating assets and liabilities and restructuring charges. Management presents thismeasure 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 activitiesand 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 controland (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 financialperformance under GAAP.

Financial Measures: Net Cash Flow

2019 2018 2019 2018

Net cash flow:Net cash provided by operating activities $ 225 $ 252 $ 964 $ 1,223 Add back (deduct): Changes in operating assets and liabilities 19 88 (69) 90 Restructuring charges 2 19 11 39 Other one-time loss — — 7 —Net cash flow 246$ 359$ 913$ 1,352$

3 Months Ended December 31,

($ in millions)


($ in millions)



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 shareattributable to Southwestern Energy stockholders, both of which exclude certain charges or amounts shown in the tables below. Management presents these measuresbecause (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 morecomparable to earnings estimates provided by securities analysts, and (iii) charges or amounts excluded cannot be reasonably estimated and guidance provided by theCompany excludes information regarding these types of items. These adjusted amounts are not a measure of financial performance under GAAP.

Financial Measures: Adjusted Net Income Attributable to Common Stock

1) 2019 primarily relates to the release of the valuation allowance. 2018 primarily relates to the exclusion of certain discrete tax adjustments associated with valuation allowance against deferred tax assets. The Company expects its 2019 tax rate to be 23.5%.

($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share)Net income attributable to common stock 110$ 0.20$ 307$ 0.54$ 891$ 1.65$ 535$ 0.93$ 815$ 1.63$ Add back (deduct):

Participating securities - mandatory convertible preferred stock — — — — — — — — 90 0.18 Impairments 8 0.01 — — 16 0.03 171 0.30 — —Restructuring 2 0.00 19 0.03 11 0.02 39 0.06 — —(Gain) loss on sale of assets, net (1) (0.00) (16) (0.03) 2 0.00 (17) (0.03) (4) (0.01) (Gain) loss on certain derivatives 14 0.03 (89) (0.16) (94) (0.17) 24 0.04 (451) (0.90) (Gain) loss on early debt extinguishment and other (1) (0.00) 9 0.02 (8) (0.01) 17 0.03 73 0.15 Legal settlements 3 0.01 1 0.00 6 0.01 9 0.02 5 0.01 Loss on foreign currency adjustment — — — — — — — — 6 0.01 Non-cash pension settlement loss 1 0.00 — — 6 0.01 — — — —Other one-time loss — — 2 0.01 10 0.02 3 0.01 (2) (0.00) Adjustments due to discrete tax items (1) (32) (0.06) (75) (0.13) (526) (0.97) (130) (0.23) (455) (0.91) Tax impact on adjustments (5) (0.01) 18 0.03 14 0.02 (61) (0.11) 142 0.28

Adjusted net income 99$ 0.18$ 176$ 0.31$ 328$ 0.61$ 590$ 1.02$ 219$ 0.44$

3 Months Ended December 31,2018

Years Ended December 31,2019 2018 20172019



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 ofassets and gains (losses) on unsettled derivatives plus write-down of inventory, non-cash stock-based compensation, restructuring charges, loss on debt extinguishment,impairments, legal settlements and foreign currency adjustments. Southwestern has included information concerning EBITDA and Adjusted EBITDA because they are used bycertain 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. EBITDAand 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 dataprepared 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 tosimilarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The tablebelow reconciles historical net income with historical Adjusted EBITDA.

Financial Measures: Adjusted EBITDA

2019 2018 2017

Net income 891$ 537$ 1,046$ Add back (deduct): Interest expense 65 124 135 Provision (benefit) for income taxes (411) 1 (93) Depreciation, depletion and amortization 471 560 504 Impairments 16 171 — Restructuring and other one-time charges 21 39 — (Gain) loss on sale of assets, net 2 (17) (4) (Gain) loss on unsettled derivatives (94) 24 (451)

(Gain) loss on early extinguishment of debt (8) 17 73 Legal settlement charges 6 9 5

Non-cash pension settlement loss 6 — 0Loss on foreign currency adjustment — — 6Adjustments due to inventory valuation and other — 3 (2)Stock based compensation expense 8 16 28

Adjusted EBITDA 973$ 1,484$ 1,247$

($ in millions)



Explanation and Reconciliation of Non-GAAPFinancial Measures: Net debt / Adj. EBITDA

1) Total debt per the balance sheet, which includes unamortized debt discount and issuance expense.

2) Total year amounts may not add due to rounding.3) Includes amounts associated with Fayetteville prior to December 2018 divestiture.

Mar 31, Jun 30, Sep 30, Dec 31, Mar 31, Jun 30, Sep 30, Dec 31, Mar 31, Jun 30, Sep 30, Dec 31,

. 2017 2017 2017 2017 2018 2018 2018 2018 2019 2019 2019 2019

Total debt (1) $ 4,630 $ 4,381 $ 4,436 $ 4,391 $ 4,393 $ 3,570 $ 3,572 $ 2,318 $ 2,319 $ 2,319 $ 2,271 $ 2,242 Subtract:

Cash and cash equivalents (1,382) (1,111) (989) (916) (958) (37) (9) (201) (366) (155) (29) (5)Net debt 3,248$ 3,270$ 3,447$ 3,475$ 3,435$ 3,533$ 3,563$ 2,117$ 1,953$ 2,164$ 2,242$ 2,237$

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019

Net income 351$ 284$ 77$ 334$ 208$ 51$ (29)$ 307$ 594$ 138$ 49$ 110$ Add back (deduct): Interest expense 32 34 31 38 39 32 29 24 14 15 17 19 Provision (benefit) for income taxes — — (14) (79) — — — 1 (426) 15 10 (10) Depreciation, depletion and amortization(2) 106 123 135 140 143 142 151 134 112 110 125 119 Impairments — — — — — — 161 — — 6 2 8 Restructuring and other one-time charges — — — — — 18 2 19 3 2 12 2 (Gain) loss on sale of assets, net (1) (2) — (1) (1) — — (16) (2) 3 — (1) (Gain) loss on unsettled derivatives (146) (173) (31) (101) (2) 56 59 (89) 22 (118) (12) 14

(Gain) loss on early extinguishment of debt 1 10 59 3 — 8 — 9 — — (7) (1) Legal settlement charges — — 5 — — 8 — 1 — — 3 3 Non-cash pension settlement loss — — — 6 — — — — — 4 1 1 Other non-cash (gain) loss — (1) — (1) 3 (1) — 2 — 9 — —Stock based compensation 7 6 9 6 6 3 4 3 2 2 2 2

Adjusted EBITDA 350$ 281$ 271$ 345$ 396$ 317$ 377$ 395$ 319$ 186$ 202$ 266$

Q1 2017 Q2 2017 Q3 2017 Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019

Net debt 3,248$ 3,270$ 3,447$ 3,475$ 3,435$ 3,533$ 3,563$ 2,117$ 1,953$ 2,164$ 2,242$ 2,237$ Adjusted EBITDA 913$ 1,065$ 1,144$ 1,247$ 1,293$ 1,329$ 1,435$ 1,484$ 1,408$ 1,276$ 1,102$ 973$ Net debt/LTM Adjusted EBITDA 3.6x 3.1x 3.0x 2.8x 2.7x 2.7x 2.5x 1.4x 1.4x 1.7x 2.0x 2.3x

($ in millions)

($ in millions)

($ in millions)

Adjusted EBITDA(2 )

Net Debt/LTM Adjusted EBITDA(3 )

Net debt is defined as short-term debt plus long-term debt less cash and cash equivalents. Adjusted EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization, expenses associated with the write-down of inventory, restructuring charges, impairments, legal settlements and gains (losses) on unsettled derivatives less gains on sale of assets over the prior 12 month period. Southwestern has included information concerning Net debt / Adjusted EBITDA because it is 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. Net debt / Adjusted EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with generally accepted accounting principles or as a measure of the Company's profitability or liquidity. Net debt / Adjusted EBITDA, as defined above, may not be comparable to similarly titled measures of other companies. The table below reconciles historical Adjusted EBITDA with historical net income.

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