October 2017 Update. Enhancing our Future NYSE: SWN

Transcription

1 October 2017 Update Enhancing our Future NYSE: SWN

2 Southwestern Energy Company General Information Southwestern 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. Investor Contacts Jennifer Stewart Senior Vice President & Chief Financial Officer - Interim Phone: (832) Fax: (832) jennifer_stewart@swn.com Bill Way President & Chief Executive Officer Phone: (832) Fax: (832) Michael Hancock Vice President, Investor Relations Phone: (832) Fax: (832) michael_hancock@swn.com 1

3 Forward-Looking Statements This presentation includes forward-looking statements. Forward-looking statements relate to future events and anticipated results of operations, business strategies and other aspects of our operations or operating results. In many cases you can identify forward-looking statements by terminology such as anticipate, intend, plan, project, estimate, continue, potential, should, could, may, will, objective, guidance, outlook, effort, expect, believe, predict, budget, projection, goal, forecast, target or similar words. Statements may be forward-looking even in the absence of these particular words. Where, in any forward-looking statement, the Company expresses an expectation or belief as to future results, such expectation or belief is expressed in good faith and believed to have a reasonable basis. However, there can be no assurance that such expectation or belief will result or be achieved. The actual results of operations can and will be affected by a variety of risks and other matters including, but not limited to, changes in commodity prices (including geographic basis differentials); changes in expected levels of natural gas and oil reserves or production; operating hazards, drilling risks, unsuccessful exploratory activities; natural disasters; limited access to capital or significantly higher cost of capital related to illiquidity or uncertainty in the domestic or international financial markets; international monetary conditions; unexpected cost increases in service or other costs related to drilling and completion activities; potential liability for remedial actions under existing or future environmental regulations; failure to obtain necessary regulatory approvals; potential liability resulting from pending or future litigation; and general domestic and international economic and political conditions; as well as changes in tax, environmental and other laws applicable to our business. Other factors that could cause actual results to differ materially from those described in the forward-looking statements include other economic, business, competitive and/or regulatory factors affecting our business generally as set forth in our filings with the Securities and Exchange Commission. Unless legally required, Southwestern Energy Company undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Cautionary Note to U.S. Investors The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. We use the terms "resource" and EUR in this presentation that the SEC s guidelines prohibit us from including in filings with the SEC. The quarterly reserves data included in this release are estimates we prepared that have not been audited by our independent reserve engineers. All such estimates are inherently more speculative than estimates of proved reserves and are subject to substantially greater risk of actually being realized. U.S. investors are urged to consider closely the oil and gas disclosures and associated risk factors in our Form 10-K and other reports and filings with the SEC. Copies are available from the SEC and from the SWN website. This presentation contains non-gaap financial measures, such as adjusted net income, adjusted EBITDA and net cash flow, including certain key statistics and estimates. We report our financial results in accordance with accounting principles generally accepted in the United States of America ( GAAP ). However, management believes certain non-gaap performance measures may provide users of this financial information additional meaningful comparisons between current results and the results of our peers and of prior periods. Please see the Appendix for definitions and reconciliations of the non-gaap financial measures that are based on reconcilable historical information. The contents of this presentation are updated as of October 26, 2017 unless otherwise indicated. 2

4 Our Strategy Premier quality, large scale assets Delivering robust value growth in core Appalachia areas underpinned by cash flow from vast Fayetteville asset High degree of operational control and flexibility Value focused capital allocation and investment practices 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 Increasing capital efficiency and margin expansion Well enhancements and cost optimization, improving returns and expanding inventory Leading FT portfolio capturing improving basis differentials Value creation across gas value chain Rigorous financial discipline Further strengthening of the balance sheet Invest within cash flow Proactive risk management Leading technology, operating and commercial capabilities Superior reservoir performance Maximizing resource access through leading drilling precision Optimizing completion techniques to enhance well productivity and economics 3

5 Strategy Delivering Results Recent Highlights Margin Expansion Well Results Q3 Highlights Renegotiated Fayetteville transportation agreement, increasing 2018 cash flow by ~$45 million, subject to FERC approval Commenced water infrastructure project in SW Appalachia that is expected to reduce total well costs by approximately $500,000 per well beginning in late 2018 Created approximately $1.4 million per well of incremental value from immediately reduced processing rates in the lean gas acreage of Southwest Appalachia while providing a competitive dry gas gathering solution in southern Utica acreage Progressed Tioga County development with first four-well development pad delivering initial production rate of over 80 MMcf per day Placed a three-well pad to sales in western Susquehanna County acreage with combined maximum rate of over 62 MMcf per day Demonstrated repeated reservoir deliverability with second Company-drilled Utica well Brought two additional encouraging Moorefield delineation wells online continuing to confirm our geologic and reservoir modeling of the play Total net production of 232 Bcfe, including 153 Bcfe from the Appalachian Basin, up 10% and 26%, compared to 3Q 2016, respectively Significantly improved debt maturity profile through successful notes offering, resulting in approximately $92 million in bond debt due prior to 2022 Realized C3+ NGL prices of $27.82 per barrel, or 58% of WTI (net of transportation costs), up 75% compared to the 3Q 2016 Added to 2018 hedge position which now has ~473 Bcf hedged at an average floor price of approximately $3/Mcf with upside potential on over 62% of hedged volumes 4

6 Strengthen the Balance Sheet Debt Maturity Schedule $ MMs $ MMs Cash balance and undrawn revolver anchors liquidity position of approximately $1.8B (1) Extended maturity profile with no significant bond maturities before 2022 Use of September bond offering proceeds used to prepay unsecured 2020 term loan in full and reduce balance of 2020 notes Cash Balance vs Secured Term Loan Bond Maturity Schedule $2,000 $2,000 $1,500 $1,500 $1,000 $1,000 No significant maturities until 2022 $500 $500 $0 Cash 20 Secured Term Loan $0 (2) (3) (1) Excludes outstanding letters of credit and minimum liquidity covenant. (2) Assumes 90% of 2020 notes retired or extended beyond 2020 prior to October 2019; otherwise, facility matures in As of September 30, 2017, the Company has successfully retired or extended 89% of the 2020 notes. (3) Maturities of $40 million retired upon maturity in October

7 Asset Overview Reserves & Production 2016 Production: 875 Bcfe 2016 Reserves: 5,253 Bcfe March 31, 2017 Reserves: >10 Tcfe* * Unaudited Northeast Appalachia 2016 Reserves 1,574 Bcf (30%) 2016 Production 350 Bcf (40%) Net acres 245,805 (12/31/16) PA Southwest Appalachia 2016 Reserves 677 Bcfe (13%) 2016 Production 148 Bcfe (17%) Net acres 321,563 (12/31/16) WV Fayetteville Shale 2016 Reserves 2,997 Bcf (57%) 2016 Production 375 Bcf (43%) Net acres 918,535 (12/31/16) Gross Drilling Locations Remaining for Assumed NYMEX Gas Prices (1) AR $3.00 $3.50 $4.00 SW Appalachia 1,925 3,400 4,200 NE Appalachia Fayetteville 675 1,575 1,575 SWN Total 2,975 5,475 6,325 (1) Assumes 10% return 6

8 Premier Asset Optionality 3 large-scale, low-risk assets provide diversification of cash flow through geographic location and product mix Gas 20% NGLs Oil 36% SW App Revenue Breakout 44% 31% 43% YTD 2017 Revenue Profile 20% 37% 36% 3/31/2017 Reserves Profile 33% NE Appalachia SW Appalachia Fayetteville NE Appalachia SW Appalachia Fayetteville 7

9 Increasing Capital Efficiency Improving F&D Decreasing proved developed F&D costs resulting from deliberate portfolio investment shift to Appalachia Increased EUR s in NE Appalachia due to changes in completion intensity and flowback methods Reducing costs through differentiating vertical integration capabilities and improving cycle times Historical F&D Results F&D of Potential Development Opportunities (2) PDP F&D (1) $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 $1.33 $1.23 $0.88 $0.75 $1.03 $0.40 $ Fay NE App SW App Rich (1) See explanation and reconciliation of proved developed (PDP) F&D on page 44. (2) Displayed F&D costs for potential development opportunities represents a hypothetical well based on expected average CLAT for full-field development. Capital based on $/foot from February 2017 guidance: Estimates Capital EUR CLAT Fayetteville $3.1 MM 3 Bcf 5,300 NE App $4.8 MM 12 Bcf 5,500 SW App Rich (3) $6.7 MM 12 Bcfe 7,500 SW App Lean (3) $6.7 MM 24 Bcfe 7,500 (1) For more information on SW App Rich and Lean wells, see slides 30 and 31. $0.28 (3) (3) SW App Lean 8

10 Southwest Appalachia Core position in premier play targeting stacked pays Gas in Place Map SWN acreage shown in yellow Bcf/Section 50 Bcf 100 Bcf 150 Bcf 200 Bcf 250 Bcf 300 Bcf Operational excellence driving inventory and margin expansion Total resource potential of 45 Tcfe with 4,200 locations Asset optionality provides flexibility to maximize value based on market conditions Well-positioned to capture improving liquids pricing Drilling and completion optimization resulting in enhanced productivity and value Company operated water infrastructure expected to be in operation in late 2018 Delineation of Utica progressing Targeting exit rate production growth of over 50% in 2017, compared to

11 Cumulative Production Cumulative Production Cumulative Production Southwest Appalachia Increasing Capital Efficiency Completion enhancements showing increased production at higher pressures Early indications showing improved productivity across the rich and lean gas windows Gen 2 completions outperforming Gen 1 completions by ~30% (MMcfe) (1) (MMcfe) (1) 1,500 1,250 1, ,000 4,000 3,000 2,000 1,000 LINDA GREATHOUSE Producing Days ALICE EDGE LINDA GREATHOUSE ALICE EDGE Completion Design Sand Loading (lb/ft) Cluster Spacing (ft) 0 4,000 3, Producing Days WILLIAM RITCHEA Previous Operator Design 1,000 1, Gen 1 2, Gen 2 2,000 5, (1) 3-Phase Production normalized to 7,500 CLAT. (MMcfe) (1) 3,000 2,500 2,000 1,500 1, Producing Days WILLIAM RITCHEA 10

12 Incremental Single Well NPV 10 ($MMs) Incremental Single Well NPV 10 ($MMs) Southwest Appalachia Incremental Value Creation Significant incremental value being created through operational enhancements and value chain expansion with large upside remaining Rich Gas Lean Gas $12 $12 $10 $8 $6 $4 $2 $2.3 $0.5 $2.8 $2.3 NGL Condensate Gas $1.3 $0.7 $1.8 $1.4 $10 $8 $6 $4 $2 $0.9 $0.5 $1.4 $2.8 $1.6 NGL Condensate Gas $1.3 $3.1 $0.1 $2.2 $0 Gen 2 Completions Water Project Current Extended Laterals Driving economic expansion Completion Optimization Price Optionality $0 Gen 2 Completions Water Project Williams Processing Agreement Current Extended Laterals Completion Optimization Price Optionality 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 11

13 Southwest Appalachia Water Infrastructure Commenced water infrastructure project to capture additional value Expected to generate savings of $500,000 per well beginning in late 2018, an ~8% improvement in F&D Reduces break-even gas price by ~$0.25/Mcf Increases the operational capability for development Improves logistics and reduces trucking traffic and costs Opportunity to capture 3 rd party business, enhancing economics even further 12

14 Bcf/d Southwest Appalachia Improving basis differentials as a result of pipeline infrastructure Over the next 4 years, executed transportation agreements will provide a pathway for ~12 BCF/d of production to leave the Southwest Appalachian region Certificates were awarded and construction has commenced on ~3.5 BCF/d of takeaway with expected inservice of late 2017 SWN transportation portfolio structured to provide access to high demand markets along the Gulf Coast while also capturing materially improving in-basin pricing Approximately 50% of SW App to be sold at premium Gulf Coast markets beginning in Southwest Appalachia Takeaway Estimated Weighted Average Sales Differential (excluding transportation) (1) Future Industry Capacity ($0.76) Existing Industry Capacity ($0.37) ($0.22) - Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 SW App (1) Basis information shown above is based on market quotes as of October 10, 2017 and assumes sales locations percentages shown on page

15 Southwest Appalachia Increasing NGL realizations driving economics in SW Appalachia NGL Composition Increasing NGL Realizations 10% 5% $ % of WTI 25% 60% $7.04 $ % of WTI $ % of WTI 16% of WTI Ethane Propane Butane Other Q Q Q Q Total NGL Realizations (after transport costs) C3+ Realizations (after transport costs) Realized over 100% increase in NGL pricing compared to 3Q 2016 Positive outlook for continued strengthening NGL economics Well positioned to capture improving ethane prices through firm transportation capacity 5% increase in NGL realizations increases cash flow by $30 - $40 MM per year Each $2.50/Bbl increase in NGL price reduces breakeven gas price by ~$0.50/Mcf 14

16 Ethane Demand (Mb/d) U.S. Ending Stocks of Ethane (Mbbls) Southwest Appalachia Increasing 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 Ethane Demand & Inventory (1) Mont Belvieu Ethane Pricing ($/gal) (2) 2,500 60,000 $0.45 2,000 48,000 $0.40 $0.35 1,500 36,000 $0.30 $0.25 1,000 24,000 $0.20 $ ,000 0 $0.10 $0.05 $- Increase of over 100% since January 2016 and over 20% from current prices Cracker Demand Exports (Land) Exports (Water) Inventory (1) Source Genscape and EIA data (2) Source OPIS & NYMEX ethane strip pricing information shown above is based on market quotes as of October 4,

17 Northeast Appalachia Delivering value now and in the future SWN Acreage Gross operated production of 1,408 MMcf/d (1,166 MMcf/d net) as of Sept 30, 2017 Achieved division s record all-time gross operated production in 3Q 2017, an increase of ~35% compared to 3Q 2016 Low cost integrated firm transportation portfolio provides access to improving pricing locations which is expected to enhance margins significantly in 2018 Improved productivity being driven by optimization of completion and flowback methods across the play Successful delineation results in Tioga area, preparing approximately 28,000 net acres for development drilling 16

18 Northeast Appalachia Improving basis differentials driving margin expansion SWN transportation portfolio structured to capture materially improving Northeast basis differentials Added approximately 140 MMcf per day of new takeaway capacity in 2Q 2017 to the portfolio at an average cost of $0.10 per Mcf, facilitating future growth Basis improvement expected to increase cash flow by over 50% over the next 3 years A $0.05/mcf improvement in differentials provides ~$20 MM impact to cash flow Estimated Weighted Average Sales Differential (excluding transportation) (1) $3.00 NYMEX Improving Margin Normalized for $3.00 NYMEX ($0.60) $0.85 $1.31 ($0.34) ($0.26) $1.12 $1.00 $0.74 $0.66 NE App LOE TOTI G&A Differentials Margin (1) Basis information shown above is based on market quotes as of October 10, 2017 and assumes sales locations percentages shown on page

19 Average Cumulative Production per Well (MMcf) Northeast Appalachia Completions 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 4,000 Susquehanna County Cumulative Production 3,500 3,000 2,500 2,000 1,500 1, Days of Production Optimized Operational Design (54 Wells) Previous Operational Design (199 Wells) 18

20 Fayetteville Significant asset with upside promise SWN Acreage Fayetteville E&P and midstream assets have generated over $1.0 billion in free cash flow in the last three years and are expected to generate approximately $425 million in 2017, supporting the growth in the Appalachian Basin Gross operated production was 1,232 MMcf/d (814 MMcf/d net) as of Sept 30, 2017 Close proximity to growing Gulf Coast demand and access to LNG export facilities Aggressively pursuing operational and commercial opportunities to drive enhanced economics Confirmed Moorefield productivity with positive results from recent delineation wells Base production enhancements directed to improve overall cash margin 19

21 Base Decline (%) Fayetteville Shallowing Base Declines SWN has the lowest production base decline of peers due to the influence of later life shallower declining Fayetteville Low base decline and robust hedging program ensures stability of future cash flow 60% Base Decline by Operator (1) 50% 40% 30% 20% 10% 0% Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 SWN (1) Source: RSEG report from September 2017 (Peers include Antero, Cabot, Chesapeake, Consol, EQT, Eclipse, RICE and Range) 20

22 Building for Tomorrow Company Objectives Driving down breakeven thresholds to expand inventory at lower commodity prices Applying ongoing technical learnings to maximize future investment economics Strengthening the balance sheet through EBITDA expansion and opportunistic debt reduction Extracting value across multiple areas of the value chain Southwest Appalachia Northeast Appalachia Unlocking 45 Tcfe resource potential by targeting stacked pays Exercising flexibility within asset to capture enhanced returns Further de-risking Utica following two delineation wells demonstrating repeated reservoir deliverability Achieving productivity enhancements through well design optimization Applying recent completion enhancements across the acreage resulting in improved productivity Successfully delineating additional acreage in Tioga, Wyoming and western Susquehanna Counties Building on operational momentum to generate free cash flow (1) Realizing improved basis differentials as infrastructure is placed in service Fayetteville Generating free cash flow (1) from sizable production base with shallowing declines Advancing geologic understanding of the Moorefield and other Fayetteville benches Maximizing price realizations through proximity to increasing Gulf Coast demand (1) Free cash flow is calculated as net cash flow less capital investments. 21

23 Delivering Shareholder Value + Rigorous financial discipline Proactive risk management Value-driven growth within cash flow Driving differentiation through environmental and regulatory standards Enhancing value from vertical integration Margin expansion through cost reductions and improved well productivity Operational and technical excellence 22

24 Appendix 23

25 Rigorous Financial Discipline Strengthen the balance sheet No significant near-term maturities Strong liquidity position of approximately $1.8B (1) Targeting long-term net debt to EBITDA of <2.0x Invest within cash flow Fully funded 2017 capital program Returns focused with flexibility to align activity with commodity prices Target investments meeting or exceeding 1.3 PVI at strip pricing Delivering value-driven growth Proactive risk management Provide protection of cash flows and ensure targeted returns with a rolling 3-year hedge program Utilize a combination of commodity and basis hedging Protect against challenging commodity price environment while retaining exposure to price upside through swaps and collars (1) Excludes outstanding letters of credit and minimum liquidity covenant. 24

26 Stringent Capital Allocation and Investment Practices Fully Funded 2017 Capital Program Dynamic portfolio management and vertical integration allowing flexibility to align activity with strip pricing Investment decisions made based on highest PVI ranking utilizing strip pricing Appalachian production expected to grow approximately 40% based on exit production rates and approximately 17% (using midpoints) over 2016 annual production volumes $1,400 $1,200 $1,300 MM $200 (1) $1,225 MM (2) Capitalized interest & expense $225 - $245 $1,000 $800 $600 $400 $1,100 (2,3) Midstream & corporate $25 - $40 Land, seismic & other E&P $115 - $130 Capital Investment Breakdown (2) $200 $ Sources 2017 Capital Investments Drilling & completions $810 - $860 $ in millions Capital Investments Net Cash Flow Proceeds from 2016 Equity Issuance (1) $500MM of proceeds from July 2016 equity offering earmarked to accelerate drilling and completions activity, with approximately $200MM expected to be invested in (2) Assumes midpoint of guidance issued in February (3) Net cash flow is net cash flow before changes in operating assets and liabilities and is a non-gaap financial measure. See explanation and reconciliation on page

27 Volumes Hedged, (Bcf) Hedging Protecting balance sheet and targeted returns Hedge Summary REM $2.29 x $2.97 x $3.30 $2.96 x $ $2.39 x $2.97 x $3.37 $2.97 x $3.56 Swaps Way Collars Way Collars Total (Bcf) Avg. Floor Price (1) $3.01 $2.99 $ $2.40 x $2.97 x $3.37 $2.40 x $2.97 x $3.37 $2.40 x $2.97 x $ $2.50 x $2.95 x $ $ $3.02 $3.02 $3.02 $3.02 $ Q4 17 Q1 18 Q2 18 Q3 18 Q Swaps 2-Way Costless Collars 3-Way Costless Collars (1) Based on an average swap or purchased put strike price. Note: Please refer to our quarterly report for the three months and nine months ended September 30, 2017 on Form 10-Q, filed with the Securities and Exchange Commission, for complete information on the Company s commodity, basis and interest rate protection. 26

28 Southwest Appalachia 27

29 Well-Positioned in Core Utica Acreage ID Operator Well Name Lateral Length (ft) UTICA 1 SWN* Hubbard 3H 5,889 2 SWN* Messenger 3H 5,821 3 SWN OE Burge 501H 8,061 4 SWN Marlin Funka 9H 4,572 1 RRC Claysville 11H 5,420 2 CVX Conner 6H 6,451 3 EQT Scotts Run ,221 4 CNX GH 9 6,141 5 GST Simms 5H 4,447 6 SGY Pribble 6H 3,605 Repeated Utica Delineation Success Initial productivity in the top quartile of WV and PA Utica industry wells (1) O.E. Burge 501H Surpassed 3 Bcf of cum production in 8 months of flowing time Sustained production at a flat rate of 15 MMcf per day at ~4,000 PSI casing pressure Marlin Funka 9H 1 Bcf of cum production in 2 months of flowing time Average 60-day rate of 17.7 MMcf per day as part of pressure management program *Drilled and completed by previous operator. (1) Source: Public data and company presentations 28

30 Bcf/d Southwest Appalachia Takeaway Increasing Gulf Coast market exposure TransCanada MXP Columbia Gas Transmission MXP (project not in service) Firm Sales ETC ETC Rover Rover Firm Firm Transportation Capacity Capacity Firm Sales 100% Sales Locations 14% 10% 5% 5% 6% 10% Year SWN Firm Transport (MMbtu/d) Reservation Rate per MMbtu Firm Sales (MMbtu/d) Rate per MMbtu Total Firm Takeaway (MMbtu/d) Annual WAVG Rate per MMbtu 80% 60% 40% 59% 21% 21% 35% 33% Nymex M2 TCO ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ % 0% 48% 54% 52% 23% 4% Gulf ,000 $ ,000 $ ,000 $0.56 No transportation fees associated with firm sales Assumes SWN Rover and TransCanada capacity in service in late 2017 and late 2018, respectively Ability to release capacity or buy third-party production to fill any excess transportation capacity Sales location percentages are based on fully utilized transportation and firm sales volumes 29

31 Southwest Appalachia Rich Gas Horizontal well performance Mmcfe/d Well Results Exceeding Expectations 10,500 9,000 7,500 6,000 4,500 3,000 1,500 0 Time Frame Historical Production 12 BCFe Type Curve 14 BCFe Type Curve Wells Placed on Production SWN Drilled & Completed Rich Gas Condensate (Normalized to 7,500 ft lateral) Average Lateral Length Days Online Average Completed Well Cost $MMs (# of wells) 1 Avg Rate For 1st 30 Days (Mcfe/d) (# of wells) 30th-Day % Gas / Condensate / NGL Production Mix Avg Rate For 1st 60 Days (Mcfe/d) (# of wells) 60th-Day % Gas / Condensate / NGL 2 nd Qtr ,353 $8.7 (1) 7,275 (10) 41 / 11 / 48 7,084 (10) 41 / 10 / 49 3 rd Qtr ,599 $6.7 (5) 7,027 (5) 34 / 17 / 49 7,391 (5) 35 / 15 / 50 4 th Qtr ,520 $8.1 (10) 7,101 (15) 32 / 23 / 44 7,605 (15) 33 / 22 / 45 1 st Qtr nd Qtr ,643 $6.0 (5) 5,347 (5) 29 / 31 / 40 5,367 (5) 30 / 29 / 41 3 rd Qtr th Qtr ,486 $5.5 (3) 4,820 (6) 35 / 23 / 42 5,548 (6) 36 / 21 / 43 1 st Qtr ,972 $7.8 (7) 7,338 (9) 36 / 17 / 47 8,054 (9) 37 / 16 / 47 2 nd Qtr ,811 $6.7 (9) 7,233 (9) 30 / 28 / 42 8,193 (9) 31 / 26 / 43 3 rd Qtr ,832 $6.2 (4) 4,497 (4) 2 30 / 28 / 42 6,551 (4) 2 30 / 26 / 44 20% 47% 33% Gas NGL Oil (1) Includes only wells drilled and completed by SWN. (2) Temporarily restricted production during the quarter. The average rate on the 60 th day was 10,600 Mcfe/d. 30

32 Southwest Appalachia Lean Gas Horizontal well performance Mmcfe/d Well Results Exceeding Expectations 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 Time Frame Historical Production 24 BCFe Type Curve 26 BCFe Type Curve Wells Placed on Production SWN Drilled & Completed Lean Gas Condensate (Normalized to 7,500 ft lateral) Average Lateral Length Days Online Average Completed Well Cost $MMs (# of wells) 1 Avg Rate For 1st 30 Days (Mcfe/d) (# of wells) 30th-Day % Gas / Condensate / NGL Production Mix Avg Rate For 1st 60 Days (Mcfe/d) (# of wells) 60th-Day % Gas / Condensate / NGL 2 nd Qtr rd Qtr th Qtr ,431 $5.3 (4) 7,150 (4) 53 / 6 / 41 7,803 (4) 54 / 5 / 41 1 st Qtr nd Qtr ,493 $4.9 (6) 5,765 (6) 52 / 9 / 40 5,977 (6) 52 / 7 / 40 3 rd Qtr th Qtr st Qtr ,593 $7.0 (4) 5,821 (4) 54 / 5 / 41 7,199 (4) 54 / 5 / 41 2 nd Qtr ,756 $9.5 (2) 2 8,057 (6) 48 / 4 / 48 9,208 (6) 48 / 4 / 48 3 rd Qtr ,016 $6.6 (10) 5,381 (8) 54 / 3 / 43 6,310 (8) 55 / 2 / 43 47% 1% 53% Gas NGL Oil (1) Includes only wells drilled and completed by SWN. (2) Includes additional capital related to completions testing 31

33 Northeast Appalachia 32

34 Bcf/d Northeast Appalachia Takeaway Low cost portfolio with extensive market reach Added ~140 MMcf per day of new takeaway $0.10 per Mcf to facilitate further growth Constitution Transport Extension Options Firm Transportation Capacity Firm Sales 100% Sales Locations 5% 7% 5% 5% Year SWN Firm Transport (MMbtu/d) Reservation Rate per MMbtu Firm Sales (MMbtu/d) Rate per MMbtu Total Firm Takeaway (MMbtu/d) Annual WAVG Rate per MMbtu 80% 33% 31% 29% 28% ,199,000 $ ,000 $0.00 1,348,000 $ % Gulf ,307,000 $ ,000 $0.00 1,450,000 $ % 20% 0% 49% 48% 47% 51% 13% 11% 18% 20% M3 Dominion Other ,376,000 $ ,000 $0.00 1,449,000 $ ,363,000 $ ,000 $0.00 1,398,000 $0.28 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 33

35 Northeast Appalachia Continued improvement Operating Statistics 25.6 $7.0 $7.0 $5.9 $6.2 $ $5.4 $ Time Frame # of wells placed to sales Average Completed Lateral Length (ft) Average Completed Well Cost ($MM) Avg Rate for 1 st 30 Days (Mcfe/d) (# of wells) Avg Rate for 1 st 60 Days (Mcfe/d) (# of wells) 1 st Qtr ,859 $6.2 6,231 (21) 6,326 (21) 2 nd Qtr ,982 $6.3 6,276 (23) 6,281 (23) 3 rd Qtr ,288 $6.3 5,852 (18) 6,054 (18) 4 th Qtr ,333 $5.9 5,814 (26) 5,800 (26) Days to Drill -65% 6,142 5,403 4,982 4,752 4,223 4,070 3, Lateral Length (ft.) +61% Well Cost ($MM) -10% Production (Bcf) 1 st Qtr ,713 $5.8 6,791 (22) 6,772 (22) 2 nd Qtr ,853 $6.7 6,039 (21) 6,095 (21) 3 rd Qtr ,512 $5.5 4,989 (26) 5,154 (26) 4 th Qtr ,405 $4.9 5,019 (31) 5,418 (31) 1 st Qtr ,659 $5.5 4,462 (3) 4,472 (3) 2 nd Qtr ,207 $6.5 7,492 (6) 7,501 (6) 3 rd Qtr ,762 $4.7 15,535 (3) 14,569 (3) 4 th Qtr ,075 $5.1 17,178 (12) 16,645 (12) 1 st Qtr ,836 $5.6 14,624 (24) 13,816 (24) 2 nd Qtr ,530 $5.1 12,659 (21) 12,230 (21) 3 rd Qtr ,093 $7.2 15,673 (6) 17,907 (4) 2016 PDP F&D of $0.59 (1) (1) See definition and reconciliation on page

36 Daily Rate, Mcf/d Northeast Appalachia Materially improved well performance Susquehanna County initial EUR increase of over 25% due to changes in completion intensity and flowback methods 20,000 Susquehanna County 18,000 16,000 14,000 12,000 10,000 Impact of third-party gathering line issues, which are expected to be resolved in the second half of ,000 6,000 4,000 2, Months of Production Previous Completion Design (199 Wells) Optimized Completion Design (54 Wells) 12 BCF EUR Curve 35

37 Daily Rate, MCF/d Northeast Appalachia Well performance by county 8,000 Company Operated Drilled Wells (Utilizing Historical Completion Designs) 7,000 6,000 5,000 4,000 3,000 2,000 1, Days of Production Bradford County Lycoming County Susquehanna County 8 BCF EUR Curve 10 BCF EUR Curve 12 BCF EUR Curve Note: Excludes downtime and exploratory wells Susquehanna County excludes wells with new completion design 36

38 Fayetteville 37

39 Fayetteville 10.9 Operating Statistics $2.8 $2.8 $2.5 $2.4 $2.6 $2.8 $3.2 Time Frame Wells Placed on Production Average IP Rate (Mcf/d) 30th-Day Avg Rate (# of wells) 60th-Day Avg Rate (# of wells) Average Lateral Length (ft) 1 st Qtr ,272 2,616 ( 105) 2,205 (105) 5, nd Qtr ,369 2,720 ( 148) 2,112 (148) 5,382 3 rd Qtr ,303 2,680 ( 106) 2,174 (106) 5,202 4 th Qtr ,840 2,472 ( 97) 1,834 (97) 5, Days to Drill -36% Well Cost ($MM) 1 st Qtr ,424 2,412 ( 99) 1,904 (99) 5,875 2 nd Qtr ,405 2,564 ( 68) 2,087 (68) 5,836 3 rd Qtr ,886 2,106 ( 50) 1,748 (50) 5,407 4 th Qtr ,277 2,520 ( 43) 2,105 (43) 5,663 4,528 4,836 4,819 5,356 5,440 5,729 5, st Qtr ,586 2,719 ( 9) 2,351 (9) 5,496 2 nd Qtr ,352 2,792 ( 6) 2,431 (6) 6,870 3 rd Qtr ,836 3,371 ( 6) 3,381 (6) 6,853 4 th Qtr ,045 1,996 ( 22) 1,984 (22) 5,547 1 st Qtr ,838 4,085 ( 12) 3,489 (12) 6, Lateral Length (ft.) +26% Production (Bcf) 2 nd Qtr ,565 3,208 ( 8) 2,454 (8) 6,763 3 rd Qtr ,744 5,447 ( 1) N/A 5, PDP F&D of $1.14 (1) (1) See definition and reconciliation on page

40 Bcf/d Fayetteville Takeaway High correlation to Henry Hub Firm Transportation Capacity Volumetric Firm Transport - 100% 80% 60% 40% Sales Locations 100% 100% 100% 100% Gulf Coast 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 ,883,333 $ $0.00 1,883,333 $ ,300,000 $ $0.00 1,300,000 $ ,300,000 $ $0.00 1,300,000 $ ,283,333 $ $0.00 1,283,333 $ % ,000 $ $ ,000 $0.10 0% Information in table and graph assumes FERC approval of recently announced firm transportation agreement with Texas Gas Transmission Sales location percentages are based on fully utilized transportation and firm sales volumes Volumetric Firm Transport Costs are usage based 39

41 Moorefield Well performance Mcf/d 6,500 6,000 5,500 6 Bcf Typecurve Moorefield Wells (1) Normalized to 6,500 CLAT 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Days of Production (1) Includes Moorefield wells on production as of September 30,

42 Fayetteville Well performance Mcf/d 5,000 4,500 4,000 4 Bcf Typecurve 3 Bcf Typecurve 2 Bcf Typecurve Fayetteville Wells Normalized to 5,300' CLAT 3,500 3,000 2,500 2,000 1,500 1, Days of Production (1) Data as of September 30, Excludes shut-in wells and wells with mechanical problems (113). 41

43 Vertical Integration 42

44 Midstream SWN Marketing 2016 Total volumes marketed (Bcfe) 1,062 YTD 2017 Total volumes marketed (Bcfe) 782 Fayetteville Shale Gathering Gathered volumes at Sept 30, 2017 (Bcf/d) 1.4 Gathering lines at Sept 30, 2017 (Miles) 2,045 Compression at Sept 30, 2017 (Horsepower) 421,515 Results for the 9 months ended Sept 30, 2017 Marketing revenues ($MM) $2,173 Gas gathering revenues ($MM) $241 Marketing purchases ($MM) $2,141 Operating costs and expenses (1) ($MM) $144 Operating income ($MM) $129 (1) Includes $47 million in depreciation and amortization expenses. 43

45 Vertical integration provides competitive advantages Strategic and economic benefit that lowers net well costs Provides improved operating efficiency and flexibility Mitigates service cost inflation Drilling Services 7 state-of-the-art drilling rigs Reduce well cost by ~$50K per well Move ~1 days faster than peers (1) High horsepower mud pump package Hydraulic Fracturing Restarted in July 2017 Total capacity of ~72,000 horsepower Sand Mine in Fayetteville Produces 30/70 and 100 mesh sized sand (1) Based on internal estimates & analysis of public data. 44

46 Other 45

47 An Industry Leader in Corporate Responsibility Model Regulatory Framework Freshwater neutral December billion gallons of water conservation Produced water reuse 37% of total Reviewed 100% of chemicals used for hydraulic fracturing in 2016 Replaced 42 chemicals Partnership with EDF Model regulation for wellbore integrity Founding member ONE Future Supply chain target < 1% Recognized by EPA Methane Challenge SWN methane emissions 0.19% LDAR 98% of facilities in 2016 Advancing Leak Detection Technology Participating in scientific studies Facilitating new technology $1.6 million charitable contributions 4,550 employee volunteer hours Supporting STEM education Contractor safe driver training Logistics Eliminated 17,000 truck deliveries Reduced mileage 376,000 miles Pipeline transport of water 46

48 BCF/d Appalachia Takeaway Capacity Improving basis differentials as a result of pipeline infrastructure Over the next 4 years, executed transportation agreements will provide a pathway for ~16 BCF/d of production to leave the Appalachian region (NE and SW) ~1.5 BCF/d of new takeaway was placed in-service in late 2016 and early 2017 Certificates were awarded and construction has commenced on ~3.5 BCF/d of takeaway with expected in-service of late 2017 From Q and forward, transportation capacity of ~8 BCF/d will likely go in-service and fill projected gas demand in the Gulf Coast, Mid Atlantic, and Southeast 0.0 Existing Takeaway DTI Leidy South EQT Mountain Valley Pipeline TCO MXP/ GXP Access South DTI Atlantic Coast Pipeline CGT Rayne Xpress TCO WB Xpress TETCO Gulf Market Expansion II Rover Pipeline Transco Atlantic Sunrise NF Northern Access Penn East Constitution Nexus Source: SWN internal analysis 47

49 TCF U.S. Natural Gas Supply & Demand Month Rolling Average 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 Source: EIA Dry Prod Net Import Consume 48

50 Financial and Operational Summary 9 Months Ended Sept 30, ($ in millions, except per share amounts) Year Ended December 31, ($ in millions, except per share amounts) Revenues $ 2,394 $ 1,752 $ 2,436 $ 3,133 $ 4,038 Adjusted EBITDA (1) $ 902 $ 479 $ 721 $ 1,471 $ 2,343 Adjusted Net Income Attributable to Common Stock (2) $ 156 $ (52) $ (7) $ 71 $ 801 Net Cash Flow (1) $ 816 $ 434 $ 645 $ 1,468 $ 2,270 Adjusted Diluted EPS (2) $ 0.31 $ (0.12) $ (0.01) $ 0.19 $ 2.27 Production (Bcfe) Avg. Realized Gas Price ($/Mcf) (3) $ 2.22 $ 1.51 $ 1.64 $ 2.37 $ 3.72 Avg. Realized Oil Price ($/Bbl) $ $ $ $ $ Avg. Realized NGL Price ($/Bbl) (3) $ $ 6.11 $ 7.46 $ 6.80 $ E&P Metrics Lease Operating Expense ($/Mcfe) $ 0.90 $ 0.87 $ 0.87 $ 0.92 $ 0.91 General and Administrative Expense ($/Mcfe) $ 0.22 $ 0.21 $ 0.22 $ 0.21 $ 0.24 Taxes, Other than Income ($/Mcfe) $ 0.10 $ 0.09 $ 0.10 $ 0.10 $ 0.11 PDP Finding Cost ($/Mcfe) (4) $ 0.75 $ 0.88 $ 1.23 (1) Net cash flow and adjusted EBITDA are non-gaap financial measures. See explanations and reconciliations on pages 50 and 52, respectively. (2) Adjusted net income attributable to common stock and adjusted diluted EPS are non-gaap financial measures. See explanations and reconciliations on page 51. (3) Includes the impact of hedges. (4) See explanation and reconciliation of PDP F&D on page

51 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. Cash flow from operating activities: 3 Months Ended Sept 30, ($ in millions) 9 Months Ended Sept 30, ($ in millions) 12 Months Ended December 31, ($ in millions) Net cash provided by operating activities $211 $172 $789 $337 $498 $1,580 $2,335 Add back (deduct): Change in operating assets and liabilities (112) (65) Restructuring charges Net cash flow $248 $173 $816 $434 $645 $1,468 $2, Guidance NYMEX - $3.25 Gas / $55.00 Oil ($ in millions) Cash flow from operating activities: Net cash provided by operating activities $1,075 - $1,125 Add back (deduct): Change in operating assets and liabilities - Net cash flow $1,075 - $1,125 50

52 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. 3 Months Ended Sept 30, 9 Months Ended Sept 30, ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) Net income (loss) attributable to common stock $ 43 $ 0.09 $ (735) $ (1.52) $ 548 $ 1.10 $ (2,514) $ (6.02) Add back (deduct): Participating securities - mandatory convertible preferred stock $ 2 $ 0.00 $ (2) $ (0.00) $ 59 $ 0.12 $ - $ - Impairment of natural gas and oil properties , (Gain) Loss on certain derivatives (31) (0.06) (81) (0.17) (350) (0.70) Adjustments due to inventory valuation and other - - (1) (0.00) (1) (0.00) Gain on sale of assets, net (3) (0.01) (2) (0.01) Restructuring and other one-time charges Legal settlements Loss on early debt extinguishment and other (3) Adjustments due to discrete tax items (1,2) (37) (0.07) (279) (0.56) Tax impact on adjustments (12) (0.03) (301) (0.63) (945) (2.27) Adjusted net income (loss) attributable to common stock $ 29 $ 0.06 $ 12 $ 0.03 $ 156 $ 0.31 $ (52) $ (0.12) 12 Months Ended December 31, ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) Net income (loss) attributable to common stock $ (2,751) $ (6.32) $ (4,662) $ (12.25) $ 924 $ 2.62 Add back (deduct): Participating securities - mandatory convertible preferred stock $ - $ - $ (13) $ (0.03) $ - $ - Impairment of natural gas and oil properties 2, , (Gain) Loss on certain derivatives (130) (0.37) Adjustments due to inventory valuation Gain on sale of assets, net (3) (0.00) (283) (0.74) - - Transaction costs Restructuring and other one-time charges Loss on early debt extinguishment and other (3) Adjustments due to discrete tax items (1,2) (46) (0.13) Tax impact on adjustments (1,074) (2.47) (2,647) (6.96) Adjusted net income (loss) attributable to common stock $ (7) $ (0.01) $ 71 $ 0.19 $ 801 $ 2.27 (1) 2017, 2016 and 2015 primarily relate to the exclusion of certain discrete tax adjustments due to an increase to the valuation allowance against the Company s deferred tax assets. (2) 2014 primarily relates to the exclusion of certain discrete tax adjustments due to a redetermination of deferred state tax liabilities to reflect updated state apportionment factors. (3) 2016 includes a $51 million loss for the redemption of certain senior notes and a $6 million loss related to the unamortized debt issuance costs and debt discounts associated with the extinguished debt which were included in other interest charges. 51

53 Explanation and Reconciliation of Non-GAAP Financial Measures: Adjusted EBITDA EBITDA is defined as net income plus interest, income tax expense, depreciation, depletion and amortization. Adjusted EBITDA is defined as EBITDA less gains (losses) on sale of assets and gains (losses) on derivatives (net of settlement) plus write-down of inventory, non-cash stock based compensation, restructuring charges and loss on debt extinguishment. Southwestern has included information concerning EBITDA and Adjusted EBITDA because they are used by certain investors as a measure of the ability of a company to service or incur indebtedness and because it is a financial measure commonly used in the energy industry. EBITDA and Adjusted EBITDA should not be considered in isolation or as a substitute for net income, net cash provided by operating activities or other income or cash flow data prepared in accordance with GAAP or as a measure of the Company's profitability or liquidity. EBITDA and Adjusted EBITDA, as defined above, may not be comparable to similarly titled measures of other companies. Net income is a financial measure calculated and presented in accordance with generally accepted accounting principles. The table below reconciles historical Adjusted EBITDA with historical net income. (1) (1) Includes impact from full cost ceiling test impairment of our natural gas and oil properties (1) 2016 (1) 2015 (1) 2014 Net income (loss) $712 ($2,433) ($2,643) ($4,556) $924 Add back (deduct): 9 Months Ended Sept 30, ($ in millions) 12 Months Ended December 31, ($ in millions) Net interest expense Provision (benefit) for income taxes (14) (20) (29) (2,005) 525 Depreciation, depletion and amortization (1) 364 2,670 2,757 8, Gain on sale of assets, net (3) (2) (3) (283) - Non-cash stock based compensation Adjustments due to inventory valuation and other (1) Restructuring and other one-time charges Legal settlements Loss on debt extinguishment (Gain) loss on derivatives excluding derivatives, settled (350) (130) Adjusted EBITDA $902 $479 $721 $1,471 $2,343 52

54 Explanation and Reconciliation: Proved Developed Finding and Development Costs Proved developed (PDP) finding and development (F&D) costs are computed here by dividing exploration and development capital costs incurred, excluding capitalized interest and expenses, for the indicated period by PDP reserve additions and proved undeveloped (PUD) conversions for that same period. At times, adjustments are made to this calculation in order to improve usefulness for investors. The methods used by Southwestern to calculate its PDP F&D costs may differ significantly from methods used by other companies to compute similar measures and, as a result, Southwestern s PDP F&D costs may not be comparable to similar measures provided by other companies. (1) 12 Months Ended December 31, Months Ended December 31, NE App SW App Fay Total PDP Adds (Bcfe): New PDP Adds PUD Conversions , Total PDP Adds ,460 1,321 1,257 Costs Incurred ($MMs): Proved Property Acquisition Costs $0 $0 $0 $0 $81 $1,455 $1 Unproved Property Acquisition Costs , Exploration Costs Development Costs ,417 1,600 1,662 Capitalized Costs Incurred $197 $290 $90 $621 $2,240 $7,221 $2,023 Subtract: Proved Property Acquisition Costs $0 $0 $0 $0 ($81) ($1,455) ($1) Unproved Property Acquisition Costs (11) (149) (3) (171) (692) (3,934) (168) Capitalized Interest and Expense (1) Associated with Development and Exploration (31) (28) (21) (91) (187) (206) (182) PDP Costs Incurred $155 $113 $66 $359 $1,280 $1,626 $1,672 PDP F&D $0.59 $0.72 $1.14 $0.75 $0.88 $1.23 $1.33 (1) Excludes capitalized interest and expenses to adjust for the impacts of the full cost accounting method. 53