October 2018 Investor Update

Transcription

1 October 2018 Investor Update Repositioning to Win Contact: Paige Penchas Vice President, Investor Relations Phone: (832) NYSE: SWN

2 Forward-Looking Statements This 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, or the Company s ability to consummate the closing of the sale of its Fayetteville Shale assets; 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, 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. 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 September 30, 2018 unless otherwise indicated. 1

3 What Defines Southwestern Energy Our strategy in action Premier quality, large scale assets Increasing capital efficiency and margin expansion Rigorous financial discipline and value focused capital allocation Our People - Leading technology, operating and commercial capabilities Appalachia-focused asset base Large, high quality, contiguous, operated acreage positions offer high degree of operational control and flexibility Focusing on liquids-rich, higher margin areas Leading gas and liquids transportation portfolio Well enhancements and cost optimization by collapsing cycle time, extending laterals and adding water infrastructure Creating value across natural gas & liquids value chain Commercial development impacting margin improvement Reducing organizational costs Ample liquidity, $2B credit facility Actively improving leverage - Debt/EBITDA target of 2x Allocating capital based on highest return projects Returns focused, growing cash flow per debtadjusted share Active rolling 3-year hedging program Reservoir management; enhancing well productivity and economics Vertical integration providing competitive advantages and lowering net well costs Leading independent gas marketer; capturing value from premium markets Recognized environmental stewardship 2

4 Delivering on Commitments Execution of three-phase strategy Stabilize Optimize and Increase 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 Committed to investing within cash flow through returns driven capital allocation 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 Reached agreement to sell 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 Fayetteville transaction represents a pivotal and deliberate step in repositioning SWN to compete and win 3

5 Growing Momentum Delivering today, building for tomorrow Selling Fayetteville Shale assets $1.865B sales price subject to adjustments, expected close in December 2018 $438MM net long term obligations assumed by buyer Strengthening balance sheet with ample liquidity Successful fall borrowing base redetermination; maintains $2B commitment after sale ~$1.3B reduction in senior notes and bank revolver outstandings at close Capturing greater value from Appalachia assets Higher returns from liquids growth Liquids growth rate exceeding gas growth Drilled record horizontal lateral in West Virginia; SWN record in Pennsylvania De-risking liquids-rich Upper Devonian Improving capital efficiency and expanding margins Identified and implemented structural and process changes to further reduce costs Interest expense savings ~$80 million/year Company restructuring savings ~$100 million/year Appalachia 71% 2018E Capital $ $1.25B (1) The Company s guidance for capital remains unchanged since issued in February That guidance assumes a $2.85 NYMEX gas price and a $60.00 oil price; excludes any impact from the sale of the Fayetteville Shale assets. (2) The Company updated its production guidance in August This graphic reflects the midpoint of the updated guidance, and excludes any impact from the sale of the Fayetteville Shale assets. (3) EBITDA is a non-gaap financial measure. See explanations and reconciliations on under Latest Guidance. (1) CI&E 19% Other 10% Appalachia 73% (2) 2018E Production Bcfe Appalachia 64% 2018E EBITDA (1,3) Fay 27% $ $1.35B Midstream 14% Fay 17% 4

6 Financial Strength Fayetteville proceeds to significantly reduce debt Net Debt / Adjusted EBITDA Pro Forma Debt Maturity Schedule (1) ($MM) 4.5x 2, x 2, x 3.0x 2.8x 2.7x 2.7x 2.5x 1, x 1, No significant maturities until Q Q Q Q Q Q Q Target 0 Cash Bonds Debt Paydown Revolver - Capacity Strengthening of balance sheet Target sustainable Debt/EBITDA of 2x Strong liquidity ~$1.5B (2) Reduced interest expense by ~$80 million annually (3) Sale of Fayetteville Shale enables debt reduction of ~$1.25B 1.3B at close $900MM senior notes tender $350MM 400MM bank revolver No significant bond maturities until 2025 (1) Pro Forma estimates as of expected close of Fayetteville transaction December 2018 (2) Includes $169MM in letters of credit and Reserve Based Loan ( RBL ) borrowings as of September 30, 2018 (3) Includes previous debt reduction, pro forma tender from Fayetteville proceeds and rating agency upgrades 5

7 Q Highlights Production (Bcfe) Weighted Avg. Realized Price, incl Hedges ($/Mcfe) Liquids Revenue ($MMs) Cash Costs ($/Mcfe) (1) 9% Increase 232 Liquids 38% increase % Increase $ % Increase $173 $1.37 4% Decrease $2.09 $82 $1.31 Q Q Natural Gas Liquids Q Q Q Q Q Q Net Cash Flow (2) ($MMs) Adjusted EBITDA (2) ($MMs) Net Debt/Adj EBITDA (2) Adjusted EPS (2) 43% Increase $248 $355 39% Increase $271 $ x 17% Decrease 317% Increase $ x $0.06 Q Q Q Q Q Q Q Q Leverage to liquids, basis and production improvements driving higher results (1) Includes LOE, G&A, TOTI and interest expense. Q excludes restructuring charges. (2) Net cash flow, adjusted diluted EPS, adjusted EBITDA and net debt to adjusted EBITDA are non-gaap financial measures. See explanations and reconciliations on pages 37, 38, 39 and 40, respectively. 6

8 SWN Asset Overview Independent natural gas & growing liquids producer Resource Potential >45 Tcfe 17 YE Proved Reserves: 14.8 Tcfe (25% Liquids) 18E Production (1) : Bcfe (14% Liquids) Northeast Appalachia 2017 Reserves 4.1 Tcf 2017 Production 395 Bcf 2018E Production (1) Bcf Southwest Appalachia 2017 Reserves 7.0 Tcfe (52% Liquids) 2017 Production 183 Bcfe (54% Liquids) 2018E Production (1) Bcfe (56% Liquids) Net Acres: 917,842 Net Acres: 290,291 Net Acres: 191,226 Fayetteville Shale (2) 2017 Reserves 3.7 Tcf 2017 Production 316 Bcf 2018E Production (1) Bcf Gross Drilling Locations Remaining for Assumed NYMEX Gas Prices and $50 oil price (3) $2.75 $3.00 $3.25 $3.50 SW Appalachia 1,575 2,275 2,625 3,700 NE Appalachia Fayetteville (2) ,125 1,625 SWN Total 2,150 3,425 4,100 5,750 (1) The Company updated its production guidance in August 2018; excludes any impact from the sale of the Fayetteville Shale assets. (2) Fayetteville Shale assets sale expected to close December (3) Assumes 10% return 7

9 Appalachia Growth Story Appalachia Adjusted EBITDA ($MMs) 406% Increase $675 $835 Appalachia Production (Bcfe) 41% Increase % % % $165 83% 83% 81% E $2.46/$43 $3.11/$51 $2.85/$60 NYMEX NYMEX NYMEX (1) E Gas Liquids (2) Investment and operational flexibility between wet and dry gas Production projected to grow 20-22% (2) in 2018 over % - 38% increase in liquids production Long-term, low-cost transport in Northeast Appalachia structured to capture materially improving basis differentials Deliberate steps to achieve self-funding future growth (1) The Company s guidance for capital remains unchanged since issued in February That guidance assumes a $2.85 NYMEX gas price and a $60.00 oil price; excludes any impact from the sale of the Fayetteville Shale assets. (2) The Company updated its production guidance in August This graph reflects the midpoint of the updated guidance. 8

10 Liquids Production and Realizations Higher liquids realizations enrich economics at lower gas prices Liquids production increased by 38% vs Q Q condensate production rate of ~10,850 barrels per day Sufficient liquids processing, fractionation and transportation capacity for growth 25% 10% 5% NGL Composition 60% Ethane Propane Butane C4+ Ethane transport direct to Gulf Coast via ATEX pipeline Increasing Liquids Production (MBbls/d) NGL Price Realization (1) ($/Bbl) Oil Price Realization (1) ($/Bbl) $14.45 $17.97 $15.42 $15.37 $21.60 $40.49 $48.05 $56.01 $60.15 $61.20 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 NGL Oil (1) Pricing realizations exclude the impact of hedges. Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 9

11 Expanding Margins in Appalachia Appalachia Margin (1) NYMEX - $3.11 NYMEX - $2.90 NYMEX - $2.46 $1.16 $ % Gas Appalachia YTD 2018 Revenue Mix 19% NGL $ YTD % Oil 29% Liquids Revenue Margins continue to expand in Appalachia, despite lower NYMEX gas prices Higher liquids pricing and production driving higher margins Improving Appalachia basis increasing realized gas pricing Focusing on commercial and operational improvements to lower operating costs (1) Margin calculated as weighted average realized price, excluding hedges, less LOE, G&A and TOTI. 10

12 Value Growth from Improving Appalachia Basis Appalachia benefitting from improving basis differentials SW Appalachia has direct access to Gulf Coast markets NE Appalachia has direct access to multiple premium markets Southwest Appalachia Estimated Weighted Average Sales Differential (excluding transportation) (1) NE Appalachia Transport SW Appalachia Transport NEAPP to Gulf $(0.07) 3% Other $ % $ % TCO $(0.24) 24% $(0.38) 34% M $(0.53) 46% $(0.49) 6% M $ % $ % DOM South $(0.52) 60% $(0.48) 53% $(0.07) 4% NYMEX Based % % SWAPP to Gulf $(0.11) 18% $(0.12) 54% *Based on current market quotes as of October 4, 2018 Legend: Sales Locations Basis, Sales % Northeast Appalachia Estimated Weighted Average Sales Differential (excluding transportation) (1) ($0.50) ($0.31) ($0.27) ($0.32) ($0.79) 61% Improvement ($0.61) 48% Improvement (1) Basis information shown above is based on market quotes as of October 4, 2018 and assumes sales locations percentages stated above. Transportation charges can be found on slides 31 and 34. Pricing provided by ICE & Platts 11

13 Southwest Appalachia Core position in premier play targeting stacked pays Drive value creation through enhanced performance 2019 development plan focused on high value liquids-rich inventory Build on operational excellence and enhance well completion efficiency Company operated water infrastructure delivering savings Incorporating data analytics in completion designs to further improve well performance Expanding economic drilling inventory Appraising liquids-rich Upper Devonian Progressing Utica/Upper Point Pleasant (UPP) delineation program (1) Previously identified as Rich Gas, containing natural gas liquids and condensate (2) Previously identified as Lean Gas, containing natural gas liquids Super Rich Gas (1) Rich Gas (2) Dry Gas Operated production as of September 2018 Gross gas 522 MMcf/d Gross liquids 110 MBbls/d Net gas 327 MMcf/d Net liquids 69 MBbls/d 12

14 Southwest Appalachia Increasing capital efficiency, doing more with less in 2018 Average Drilled Lateral Length (ft) Number of Stages Pumped/Day (1) Facility Installation Time (days) 7% Increase 7,379 ~ 7,900 15, % Increase % Decrease E SWN Record Drilling Targeted land acquisition to extend lateral lengths Increasing drilled average lateral lengths to >8,500 ft in 2H 2018 Drilled two ~15,000 ft laterals in Q Each 500 ft increase in lateral length increases expected net present value per well by ~$650K 2017 Q Q Q SWN Record Avg Zipper Only Completions Enhancing designs through increased sand loading and tighter stage spacing Increasing number of stages pumped per day 30% increase in completion stage run rate increases net present value per well by ~$400K Improving sand and water logistics 2017 Q Q Q SWN Record Facilities Improving facility cycle times as a result of pre-building efforts Accelerating wells to sales, resulting in accelerated production (1) Q averages based on wells in the Panhandle area 13

15 Liquids-Rich Upper Devonian Potential Upper Devonian ~9 Tcfe of resource potential ~100,000 acres 150 feet above the Marcellus Initial unbound well test (July 2018) Encouraging early results Similar performance to rich Marcellus wells 30 day rate of 12.4 MMcfe per day, 45% liquids Upside to Upper Devonian Utilizes existing Marcellus infrastructure Well cost in line with Marcellus wells in the area Additive to our liquids-rich inventory Additional testing planned for 2019 SWN acreage Initial test well 14

16 Well Positioned in Core Utica/UPP Acreage Progressing technical understanding of 15+ Tcf of resource potential Cost effectively accelerating learnings through industry data trades Estimated $600MM of trade value Acquired data on 19 wells Included some science and seismic data Primary goal is reducing well costs Midstream dry gas solutions in place with competitive pricing 3-D seismic planned in 2019 Source: Public data, company presentations and data trades SWN acreage SWN wells Other operator wells 15

17 Northeast Appalachia Delivering value now and in the future Drive value creation through enhanced performance Free cash flow positive asset Enhanced completions efficiency includes increased stages per day, tighter stage spacing and optimized flowback methods Expanded gathering capacity across Tioga and Susquehanna assets Pursue future growth and expand economic drilling inventory Expanding core drilling locations in Tioga area Appraisal of stacked pay opportunities Operated production as of September 2018 Gross - 1,534 MMcf/d Net - 1,261 MMcf/d 16

18 Northeast Appalachia Enhancing Tioga area inventory Area Highlights Acreage position ~37,500 net acres Gross production as of Sept 30, 2018 ~201 MMcf/d Q Highlights Placed 3 wells to sales Average lateral length ~8,100 feet 2018 wells outperforming 1 st development pad by up to ~20% with an average IP of 26.7 MMcf/d Initial phase of water infrastructure in service Recently announced Joint Development Agreement Covers ~6,000 acres (SWN WI 67%) Expands core inventory by 23 wells Adds ~500 Bcf of gross resource Leverages existing gathering infrastructure Allows for laterals of ~11,000 ft Installing water infrastructure, resulting in expected $400K/well savings Building Scale in Tioga 17

19 Vertical Integration Competitive advantages increase capital efficiency Strategic and economic benefit Provides improved operating efficiency and flexibility Mitigates service cost inflation Own, operate rigs and other services Progressing water infrastructure project in Southwest Appalachia Expected to generate savings of $500K/well Improves logistics and reduces trucking traffic and costs 18

20 An Industry Leader in Corporate Responsibility Freshwater neutral since December 2016 Reviewed 100% of chemicals used for operations since 2016 Gold Certification by IES (Independent Energy Standards) Founding member of consortium Targeting a less than 1% emission rate across natural gas industry API Voluntary Methane Reduction Program Advancing Technology to Reduce Methane Emissions Company-wide Leak Detection and Repair (LDAR) Programs Participating in scientific studies Facilitating new technology $2.3 million charitable contributions 4,056 employee volunteer hours Supporting STEM education Contractor safe driver training Logistics Eliminated truck deliveries through pipeline transport of water 19

21 Repositioning to Win Fayetteville sale expected to close December 2018 Vast Appalachia acreage, inventory, and growing multi-bench liquids exposure Strict capital allocation delivering returns-focused growth Margin expansion through cost reductions, improved well productivity, and vertical integration Strong balance sheet and liquidity Active commodity, basis hedging program 20

22 Appendix 21 21

23 Environmental, Social and Governance Board independence Board tenure 8 out of 9 directors are independent Bill Way, President and CEO, is sole nonindependent director Added 4 new directors since 2017 Average board member tenure is less than 5 years Board diversity Best practices 44% diverse (gender, nationality, ethnicity) 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 Social Independent directors approve compensation Mix of awards weighted heavily on long term equity based incentives Relative and absolute total shareholder return Cash flow per debt-adjusted share metric Stock ownership requirement Compensation committee retains independent consultant 24-hour community hotline in all operating areas Employee volunteerism well established within SWN culture Environmental and safety Annual bonus metrics include environmental and safety performance Core values of our culture Certified green gas producer Advanced leak detection technology Active participant in coalitions focused on reducing methane emissions Freshwater neutral 22

24 Improving Proved Developed (PD) Finding & Development Costs PD F&D is a metric that evaluates capital efficiency SWN s PDP F&D has improved by over 40% as a result of: Shifting capital to higher return Appalachia projects Optimizing drilling and completion designs increasing EUR s Lowering costs through extended laterals, improving cycle times and increasing stages per day Historical PD F&D Results PD F&D of Development Opportunities (2) $1.40 $1.20 $1.00 $0.80 $1.23 $ % Improvement $0.75 $0.72 $1.40 $1.20 $1.00 $0.80 $0.90 $0.60 $0.40 $0.60 $0.40 $0.43 $0.49 $0.28 $0.20 $0.20 $ (1) See explanation and reconciliation of proved developed (PD) F&D on page 40. (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 Super Rich and Rich wells, see slides 28 and 29. (4) Previously identified as Rich Gas, containing natural gas liquids and condensate (5) Previously identified as Lean Gas, containing natural gas liquids $0.00 Fay NE App SW App Super Rich SW App Rich (3,4) (3,5) Estimates Capital EUR CLAT Fayetteville $2.7 MM 3 Bcf 5,300 NE App $6.0 MM 14 Bcf 6,500 SW App Super Rich (3,4) $7.9 MM 16 Bcfe 7,500 SW App Rich (3,5) $7.9 MM 28 Bcfe 7,500 23

25 Hedging Protecting cash flow and returns (1) Does not include basis or NGL hedges. Financial NYMEX hedges based on an average swap or purchased put strike price as of September 28, 2018 (2) Amounts may not add due to rounding Note: Please refer to our Q quarterly report on Form 10-Q filed with the Securities and Exchange Commission for complete information on the Company s commodity and basis protection 24

26 Natural Liquids Hedging Protecting cash flow and returns Ethane Hedge Summary Quarter Volume (Bbl/day) Weighted Average Price ($/gal) Q ,100 $0.32 Q ,100 $0.32 Q ,100 $0.32 Q ,100 $0.32 Q ,100 $0.32 Propane Hedge Summary Quarter Volume (Bbl/day) Weighted Average Price ($/gal) Q ,450 $0.83 Q ,750 $0.78 Q ,250 $0.78 Q ,250 $0.78 Q ,250 $

27 2017 Proved Reserves Growth Year-end Reserve Profile (Tcfe) 2017 Proved Reserves 181% Increase Proved reserves Tcfe (181% increase) 75% natural gas and 25% liquids 46% proved undeveloped Appalachia reserves Tcfe (393% increase) Appalachia represents 75% of total reserves Pre-tax PV-10 value - $5.8 billion (247% increase) Appalachia represents 66% of total value Reserve life index 16.5 years (175% increase) Appalachia Fayetteville Reserve Growth by Commodity Pre-tax PV10 ($Bs) 93% 75% 247% Increase $ Tcfe Tcfe $2.0 7% 25% $1.7 $3.8 $1.3 Natural Gas Liquids $ Appalachia Fayetteville 26

28 Southwest Appalachia 27 27

29 Mmcfe/d Southwest Appalachia Super Rich Gas Well performance Well Results Exceeding Expectations SWN Drilled & Completed Super Rich Gas (1) Condensate (Normalized to 7,500 ft lateral) Gen 1 Completions (42 wells) 12 BCFe Type Curve 16 BCFe Type Curve 20 BCFe Type Curve Gen 2 Completions (58 wells) 14,000 12,000 10,000 8,000 6,000 4,000 2, Days Online 15% 48% PRODUCTION MIX 37% Gas NGL Oil Time Frame Wells Placed on Production Average Lateral Length Average Completed Well Cost $MMs (# of wells) (2) 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 ,103 $5.7 (8) 5,078 (11) 32 / 26 / 42 5,481 (11) 32 / 25 / 43 1 st Qtr ,346 $7.6 (5) 7,308 (7) 34 / 20 / 46 8,049 (7) 35 / 19 / 46 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) (3) 30 / 28 / 42 6,551 (4) (3) 30 / 26 / 44 4 th Qtr ,256 $8.8 (7) 6,936 (11) (4) 33 / 24 / 43 6,849 (11) (4) 33 / 23 / 44 1 st Qtr ,837 $9.1 (12) 8,402 (12) 32 / 24 / 44 8,950 (12) 32 / 22 / 46 2 nd Qtr ,851 $9.3 (26) 6,415 (26) 32 / 28 / 40 6,608 (26) 33 / 26 / 41 3 rd Qtr ,149 $8.5 (14) 7,934 (14) 34 / 23 / 43 7,659 (4) 35 / 21 / 44 (1) Previously identified as Rich Gas, containing natural gas liquids and condensate (2) Includes only wells drilled and completed by SWN (3) Temporarily restricted production during the quarter. The average rate on the 60 th day was 10,600 Mcfe/day (4) Includes 4 wells drilled and completed by previous operator. Excluding these wells, the avg 30 th day rate was 8,646 Mcfe/day and the avg 60 th day rate was 8,478 Mcfe/day 28

30 Mmcfe/d Southwest Appalachia Rich Gas Well performance Well Results Exceeding Expectations SWN Drilled & Completed Rich Gas (1) Condensate (Normalized to 7,500 ft lateral) Gen 1 Completions (22 wells) 24 BCFe Type Curve 30 BCFe Type Curve 36 BCFe Type Curve Gen 2 Completions (8 wells) 18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2, Days Online 47% 1% PRODUCTION MIX 52% Gas NGL Oil Time Frame Wells Placed on Production Average Lateral Length Average Completed Well Cost $MMs (# of wells) (2) 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 ,493 $4.9 (6) 5,765 (6) 51 / 9 / 40 5,977 (6) 52 / 7 / 41 1 st Qtr ,783 $7.6 (6) 6,301 (6) 50 / 5 / 45 7,423 (6) 50 / 5 / 45 2 nd Qtr ,756 $9.5 (2) (3) 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 4 th Qtr st Qtr ,842 $10.5 (2) (3) 11,095 (2) 44 / 3 / 53 11,290 (2) 44 / 3 / 53 2 nd Qtr rd Qtr 2018 (4) 3 5,910 $9.3 (2) 13,339 (2) 55 / 1 / 44 12,332 (2) 55 / 1 / 44 (1) Previously identified as Lean Gas, containing natural gas liquids (2) Includes only wells drilled and completed by SWN (3) Includes additional capital related to completions testing (4) Excludes 1 Upper Devonian well from the data set. For this well the 30 th day avg = 12,418 Mcfe/day and 60 th day = 11,919 Mcfe/day 29

31 Incremental Single Well NPV ($M) Incremental Single Well NPV ($M) Southwest Appalachia Incremental value creation Significant incremental value being created through operational enhancements and value chain expansion with large upside remaining Super Rich Gas (1) Rich Gas (2) $12 $12 $10 $8 $6 $4 $2 $2.3 $0.5 $2.8 $2.3 $0.4 NGL Condensate $1.3 Gas $0.7 $1.8 $1.4 $10 $8 $6 $4 $2 $0.9 $0.5 $1.4 $2.8 $1.6 $0.4 NGL Condensate Gas $1.3 $3.1 $0.1 $2.2 $0 Enhanced Completions Water Project Current Extended Laterals Operational Efficiency Further Completion Optimization Price Optionality $0 Enhanced Completions Water Project Williams Processing Agreement Current Extended Laterals Operational Efficiency Further Completion Optimization Driving economic expansion Standard design 7,500 CLAT, Gen 1 completion designs, optimized lateral placement, drawdown management Enhanced 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 Operational efficiency 30% increase in completion stages/day run rate Further 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 Price Optionality (1) Previously identified as Rich gas, containing natural gas liquids and condensate (2) Previously identified as Lean Gas, containing natural gas liquids 30

32 Southwest Appalachia Takeaway Increasing Gulf Coast market exposure 100% 12% Sales Locations 5% 5% 5% 80% 60% 40% 20% 0% 24% 34% 33% 33% 6% 10% 10% 46% 54% 52% 52% 18% Gulf M2 TCO Nymex 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 ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $ ,000 $0.56 No transportation fees associated with firm sales Assumes SWN Rover and TransCanada capacity in service in Q 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 31

33 Northeast Appalachia 32 32

34 Northeast Appalachia Well performance SWN Drilled & Completed Dry Gas (Normalized to 6,500 ft lateral) Time Frame Wells Placed on Production Average Lateral Length Average Completed Well Cost $MMs (# of wells) Avg Rate For 1st 30 Days (Mcf/d) (# of wells) Avg Rate For 1st 60 Days (Mcf/d) (# of wells) ,142 $5.3 12,962 (24) 12,578 (24) 1 st Qtr ,034 $6.0 14,624 (24) 13,816 (24) 2 nd Qtr ,530 $5.1 12,271 (21) 11,928 (21) 3 rd Qtr ,007 $7.4 15,767 (15) 15,321 (15) 4 th Qtr ,754 $5.4 15,112 (23) 14,294 (23) 1 st Qtr ,360 $6.2 17,304 (17) 16,034 (17) 2 nd Qtr ,748 $8.3 (1) 17,636 (14) (2) 16,186 (14) (2) 3 rd Qtr ,960 $7.0 13,718 (14) 14,556 (9) (1) Cost include amounts for delineation and science (2) There are 3 wells with tubing run that are excluded from the data set. For these 3 wells 30 th day avg = 5,856 Mcf/day and 60 th day = 5,877 Mcf/day 33

35 Northeast Appalachia Takeaway Low cost portfolio with extensive market reach 100% 80% 60% 11% 26% Sales Locations 17% 21% 22% 26% 27% 29% 40% 20% 60% 53% 47% 44% 0% 3% 4% 5% 5% Gulf Dominion M3 Other 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 ,330,000 $ ,000 $0.00 1,478,000 $ ,418,000 $ ,000 $0.00 1,501,000 $ ,363,000 $ ,000 $0.00 1,398,000 $ ,316,000 $ ,000 $0.00 1,351,000 $0.31 No transportation fees associated with firm sales Assumes Constitution in service in April 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 34

36 Financial and Operational Summary 9 Months Ended September 30, ($ in millions, except per share amounts) Year Ended December 31, ($ in millions, except per share amounts) Revenues $ 2,687 $ 2,394 $ 3,203 $ 2,436 $ 3,133 Adjusted EBITDA (1) $ 1,090 $ 902 $ 1,247 $ 721 $ 1,471 Adjusted Net Income (Loss) Attributable to Common Stock (2) $ 414 $ 156 $ 219 $ (7) $ 71 Net Cash Flow (1) $ 993 $ 816 $ 1,138 $ 645 $ 1,468 Adjusted Diluted EPS (2) $ 0.71 $ 0.31 $ 0.44 $ (0.01) $ 0.19 Production (Bcfe) Avg. Realized Gas Price ($/Mcf) (3) $ 2.31 $ 2.22 $ 2.19 $ 1.64 $ 2.37 Avg. Realized Oil Price ($/Bbl) (3) $ $ $ $ $ Avg. Realized NGL Price ($/Bbl) (3) $ $ $ $ 7.46 $ 6.80 E&P Metrics Lease Operating Expense ($/Mcfe) $ 0.93 $ 0.90 $ 0.90 $ 0.87 $ 0.92 General and Administrative Expense ($/Mcfe) $ 0.19 Taxes, Other than Income ($/Mcfe) $ 0.08 (8) (9) $ 0.22 (5) $ 0.22 (5) $ 0.22 $ 0.10 $ 0.10 $ 0.10 PD Finding Cost ($/Mcfe) (4) $ 0.72 $ 0.75 $ 0.88 (6) (7) $ $ (1) Net cash flow and adjusted EBITDA are non-gaap financial measures. See explanations and reconciliations on pages 36 and 38, respectively. (2) Adjusted net income attributable to common stock and adjusted diluted EPS are non-gaap financial measures. See explanations and reconciliations on page 37. (3) Includes the impact of hedges. (4) See explanation and reconciliation of PDP F&D on page 40. (5) Excludes $11 million of legal settlements for the year ended December 31, (6) Excludes $83 million of restructuring and other one-time charges for the year ended December 31, (7) Excludes $3 million on restructuring charges for the year ended December 31, (8) Excludes $17 million in restructuring charges and $8 million in legal settlements for the nine months ended September 30, (9) Excludes $1 million in restructuring charges for the nine months ended September 30,

37 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 $ 307 $ 211 $ 971 $ 789 $ 1,097 $ 498 $ 1,580 Add back (deduct): Change in operating assets and liabilities (112) Restructuring charges Net cash flow $355 $248 $993 $816 $1,138 $645 $1,468 36

38 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 September 30, 9 Months Ended September 30, ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) Net income attributable to common stock $ (29) $ (0.05) $ 43 $ 0.09 $ 230 $ 0.39 $ 548 $ 1.10 Add back (deduct): Participating securities - mandatory convertible preferred stock (1) Impairment (Gain) loss on certain derivatives (31) (0.06) (350) (0.70) Adjustments due to inventory valuation (1) - Gain on sale of assets, net (1) - (3) (0.01) Restructuring and other one-time charges Legal settlements Loss on early debt extinguishment and other Adjustments due to discrete tax items (1) (37) (0.07) (56) (0.10) (279) (0.56) Tax impact on adjustments (55) (0.09) (12) (0.03) (79) (0.13) Adjusted net income attributable to common stock $ 146 $ 0.25 $ 29 $ 0.06 $ 414 $ 0.71 $ 156 $ Months Ended December 31, ($ in millions) (per share) ($ in millions) (per share) ($ in millions) (per share) Net income (loss) attributable to common stock $ 815 $ 1.63 $ (2,751) $ (6.32) $ (4,662) $ (12.25) Add back (deduct): Participating securities - mandatory convertible preferred stock $ 90 $ 0.18 $ - $ - $ (13) $ (0.03) Impairment - - 2, , (Gain) Loss on certain derivatives (451) (0.90) Adjustments due to inventory valuation (2) (0.00) Loss on foreign currency adjustment Gain on sale of assets, net (4) (0.01) (3) (0.00) (283) (0.74) Transaction costs Restructuring and other one-time charges Legal settlements Loss on early debt extinguishment and other (1) Adjustments due to discrete tax items (1) (455) (0.91) Tax impact on adjustments (1,074) (2.47) (2,647) (6.96) Adjusted net income (loss) $ 219 $ 0.44 $ (7) $ (0.01) $ 71 $ 0.19 (1) Primarily relates to the exclusion of certain discrete tax adjustments due to an increase to the valuation allowance against the Company s deferred tax assets 37

39 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 stockbased 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 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 (1) 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. 9 Months Ended Sept 30, 12 Months Ended December 31, 2018 (1) (1) 2015 (1) Net income (loss) $ 230 $ 712 $ 1,046 $ (2,643) $ (4,556) Add back (deduct): ($ in millions) ($ in millions) Net interest expense Provision (benefit) for income taxes - (14) (93) (29) (2,005) Depreciation, depletion and amortization ,757 8,041 Gain on sale of assets, net (1) (3) (4) (3) (283) Impairments Stock based compensation expense Adjustments due to inventory valuation and other 2 (1) (2) 3 32 Restructuring and other one-time charges Legal settlements Loss on foreign currency adjustment Loss on early extinguishment of debt (Gain) loss on derivatives excluding derivatives, settled 113 (350) (451) Adjusted EBITDA $1,090 $902 $1,247 $721 $1,471 (1) 2018 includes $10 million impairment related to certain non-core gathering assets and 2016 and 2015 includes impact from full cost ceiling test impairment of our natural gas and oil properties. 38

40 Explanation and Reconciliation of Non-GAAP Financial Measures: Net debt / LTM Adj. EBITDA Net debt is defined as short-term debt plus long-term debt less cash and cash equivalents. LTM 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 / LTM 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 / LTM 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 / LTM 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. Dec 31, Mar 31, Jun 30, Sep 30, Dec 31, Mar 31, Jun 30, Sep 30, ($ in millions) Net debt: Total debt $ 4,653 $ 4,630 $ 4,381 $ 4,436 $ 4,391 $ 4,393 $ 3,570 $ 3,572 Subtract: Cash and cash equivalents (1,423) (1,382) (1,111) (989) (916) (958) (37) (9) Net debt $ 3,230 $ 3,248 $ 3,270 $ 3,447 $ 3,475 $ 3,435 $ 3,533 $ 3,563 Adjusted EBITDA* Q Q Q Q Q Q Q Q Q Q Q ($ in millions) Net income (loss) $ (1,132) $ (593) $ (708) $ (210) $ 351 $ 284 $ 77 $ 334 $ 208 $ 51 $ (29) Add back (deduct): Net interest expense Provision (benefit) for income taxes 1 (1) (20) (9) - - (14) (79) Depreciation, depletion and amortization (1) 1, Impairments Gain on sale of assets, net - (2) - - (1) (2) - (2) (1) - - Non-cash stock based compensation Adjustments due to inventory valuation and other 3 1 (1) - - (1) (1) - Legal settlements Restructuring and other one-time charges Loss on early extinguishment of debt (Gain) loss on certain derivatives (81) 324 (146) (173) (31) (101) (2) Adjusted EBITDA $ 158 $ 129 $ 192 $ 242 $ 350 $ 281 $ 271 $ 345 $ 396 $ 317 $ 377 Net Debt/LTM Adjusted EBITDA 2016 Q Q Q Q Q Q Q ($ in millions) Net debt $ 3,230 $ 3,248 $ 3,270 $ 3,447 $ 3,475 $ 3,435 $ 3,533 $ 3,563 Adjusted EBITDA $ 721 $ 913 $ 1,065 $ 1,144 $ 1,247 $ 1,293 $ 1,329 $ 1,435 Net debt/ltm Adjusted EBITDA 4.5x 3.6x 3.1x 3.0x 2.8x 2.7x 2.7x 2.5x *Total year amounts may not add due to rounding. (1) Includes impact from full cost ceiling test impairment of our natural gas and oil properties. 39

41 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) 12 Months Ended December 31, Total PD Adds (Bcfe): New PD Adds 1, PUD Conversions , Total PD Adds 1, ,460 1,321 Costs Incurred ($MMs): Proved Property Acquisition Costs $0 $0 $81 $1,455 Unproved Property Acquisition Costs ,934 Exploration Costs Development Costs 1, ,417 1,600 Capitalized Costs Incurred $1,240 $621 $2,240 $7,221 Subtract ($MMs): 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 (1) Excludes capitalized interest and expenses to adjust for the impacts of the full cost accounting method 40