Williams January Investor Meetings January 2019

Transcription

1 NYSE: WMB williams.com WE MAKE ENERGY HAPPEN Williams January Investor Meetings January 2019 WILLIAMS COMPANIES HEADQUARTERS Tulsa, Oklahoma

2 Williams is a unique large-scale, low-volatility, growing natural gas infrastructure company with strong investor upside STABILITY > Volume-driven, natural gas strategy drives low volatility in earnings and cash flow > Advantaged and irreplaceable asset base handling 30% of U.S. low-cost natural gas supplies > Large-scale energy company: ~$52 billion enterprise value with Investment Grade credit ratings > 2019 gross margin projected to be ~97% fee-based > Met or exceeded Adjusted EBITDA street consensus each of the last 11 quarters (1) > Exceeded midpoint for 2017 key guidance metrics; 2018 trending toward high end of range > ~$1.25 billion excess cash available after dividends in 2019 WMB Median S&P 500 WMB vs. S&P 500 Approximate Current Dividend 5.8% 2.2% 163.6% Yield (2) GROWTH > Nation s largest and fastest growing interstate natural gas pipeline system, Transco, with unrivaled proximity to growing Mid-Atlantic, Southeast and Gulf Coast demand centers > 15% Northeast G&P gathered volume CAGR expected Adjusted EPS CAGR (2) ( ) 18.9% 13.6% 39.0% > 18.9% Adjusted EPS growth CAGR expected despite $3.4B in asset sales VALUATION > 10% Adjusted EBITDA growth ; expecting 5-7% annual Adjusted EBITDA growth longer term beyond 2019 > Attractive current dividend yield of 5.8% (2) with strong coverage > 10.4x EV / 2019 EBITDA multiple (2) below long-term historical average of 12.8x (3) > Long-term historical 12.8x multiple (3) implies a $34 stock price which aligns with sell-side consensus target price, providing for 44% upside to current price (2) Adjusted EBITDA Growth (2) ( ) Dividend Growth (2) ( ) 9.9% 7.1% 39.4% 12.5% 6.7% 86.6% (1) Per S&P Capital IQ, Williams adjusted EBITDA exceeded or was within 2% of the consensus estimate for EBITDA in each quarter 1Q Q (2) Data and estimates as of January 4, Median S&P growth rates based on Bloomberg consensus estimates. WMB growth rates based on midpoint of guidance. (3) Represents peer average EV / NTM EBITDA multiple from January 1, 2013 to current; peers include ENB, EPD, ET, KMI, OKE, TRGP, and TRP Note: This slide contains non-gaap financial measures. A reconciliation of all non-gaap financial measures used in this presentation to their nearest GAAP comparable financial measures are included at the back of this presentation. 2

3 Consistent strategy focused on natural gas volume growth WILLIAMS HANDLES ~30% OF U.S. NATURAL GAS VOLUMES Gas End Users Wellhead (onshore and Offshore) Gathering (onshore and Offshore) 22.4 Bcf/d 18,670 miles Gas Processing Plants (onshore and Offshore) 6.9 Bcf/d inlet Natural Gas Transportation Lines / Storage 21.8 MMdth/d capacity 14,530 miles Industrial Power Residential/ Commercial Transport Exports Mixed Natural Gas Liquids Fractionation Facilities 383 Mbbl/d 317 Mbbl/d Source: Figures represent 100% capacity for operated assets, including those in which Williams has a share of ownership; NGL storage includes capacity owned and under long-term lease. All data as of December 31, 2017 plus the addition of Atlantic Sunrise Transco expansion to the natural gas transportation statistics. DJ Basin acquisition and Four Corners assets sale of 2H 2018 not accounted for in statistics. Multiple Products Storage 22.4 MMbbl Transportation Lines / Rail and Truck 575 Mbbl/d Olefins Plant Other NGL End Users Olefins End Users 3

4 Connecting the best supplies to the best markets with advantaged infrastructure Williams U.S. Asset Map NORTHEAST G&P Operating Area > Large-scale asset footprint in place > Significant production growth driven by infrastructure de-bottlenecking > Capital efficient expansions linked to existing assets WEST Operating Area > Extensive portfolio of reliable assets connecting sources of supply to demand markets > Stable cash flows and operational efficiencies driving results > Growth opportunities continue to reinforce long-term stability ATLANTIC GULF Operating Area > Irreplaceable infrastructure with low-risk revenue stream > Unmatched growth opportunity linked to existing assets > Unique footprint with access to low-cost supply sources and growing demand centers 4

5 Industry leading board of directors focused on capital discipline and long-term growth Alan Armstrong Inside Director President and CEO, Williams Director since 2011 Stephen W. Bergstrom Independent Director, Chairman Former President and CEO, general partner American Midstream Partners GP, LLC Director since 2016 Nancy K. Buese Independent Director Executive Vice President and CFO, Newmont Mining Corporation Director since 2018 Stephen I. Chazen Independent Director Former President and CEO, Occidental Petroleum Corporation Director since 2016 Charles Casey Cogut Independent Director Retired Partner, Simpson Thacher & Bartlett LLP Director since 2016 Kathleen B. Cooper Independent Director President, Cooper Strategies Intl. LLC Director since 2006 Michael A. Creel Independent Director Former CEO, Enterprise Products Partners LP Director since 2016 Vicki L. Fuller Independent Director Former Chief Investment Officer, New York State Common Retirement Fund Director since 2018 Peter A. Ragauss Independent Director Former Senior Vice President and CFO, Baker Hughes Incorporated Director since 2016 Scott D. Sheffield Independent Director Chairman and Former CEO, Pioneer Natural Resources Company Director since 2016 Murray D. Smith Independent Director President, Murray Smith and Associates; former Minister of Energy for Alberta, Canada Director since 2012 William H. Spence Independent Director Chairman, President and CEO, PPL Corporation Director since 2016 Joseph H. Williams Honorary Director 5

6 Leadership team focused on driving toward sustainable, long-term growth Leadership & Talent Development > Organization aligned around our focused strategy > Focusing resources on regulatory, permitting and government affairs to increase project execution effectiveness Alan Armstrong President and Chief Executive Officer Micheal Dunn Executive Vice President and Chief Operating Officer Chad Zamarin Senior Vice President, Corporate Strategic Development John Chandler Senior Vice President and Chief Financial Officer T. Lane Wilson Senior Vice President and General Counsel Debbie Cowan Senior Vice President, Chief Human Resources Officer 6

7 Strong leadership commitment to sustainable business practices SAFETY > Strong safety reporting and continuous improvement culture > Robust Pipeline Integrity Management Program > Performing better than industry benchmark for Total Recordable Injury Rate (TRIR) > Goal of 15% reduction of process safety incidents; 25% reduction since last year > Strong commitment to safety and operational discipline by 12 Life Critical Operating Requirements being institutionalized > Leading damage prevention and public awareness programs ENVIRONMENTAL > Comprehensive Integrated Management System operationalizes EHS management with specific policies, procedures and standards; includes external and internal audits > Extensive environmental monitoring and measurement including emissions tracking and reporting > Signatory to INGAA s Methane Emissions Commitments to minimize methane emissions > Proud history of voluntary environmental conservation and restoration projects that exceed regulatory requirements GOVERNANCE > Diverse and independent board comprised of industry leaders > Oversight on ESG issues from EHS, Nominating and Governance Committees > Compensation aligned with business strategies, including safety performance > Committed to increased diversity SOCIAL > Dedicated to excellence in land use and landowner relationships > Stakeholder input resulting in more than 400 changes to Atlantic Sunrise s pipeline route > $107 million total charitable giving in last decade to more than 8,000 organizations 7

8 A history of industry recognition 2018 > International Association for Public Participation s Core Values Award and Project of the Year Award for Atlantic Sunrise project > Platts 2018 #1 Midstream Company 2017 > Forbes U.S. Best Large Employers #22 > SGA Environmental Excellence Award for Stewardship 2016 > Forbes America s Best Employers > SGA Environmental Excellence Award for Stewardship > New York Landmarks Conservancy Lucy G. Moses Award 2015 > Fortune Magazine #1 Most Admired U.S. Energy Company > Platts 2015 Global Energy Awards Midstream Leader Award > ENR MidAtlantic Best Project Energy/Industrial > SGA Environmental Excellence Award 8

9 Williams regulated gas pipelines located in most densely populated areas of United States, creating premier competitive advantage U.S. Counties Color-coded by Population Density vs. Williams Regulated Natural Gas Pipelines Legend Northwest Pipeline Transco Population per sq. mile 50 or less or more Gulfstream Source: Data based off 2012 Census estimates 2019 The Williams Companies, Inc. All rights reserved. Williams January Investor Meetings I January

10 Williams Northeast G&P located in basin with largest recoverable gas reserves at the lowest cost U.S. Key Production Basins vs. Williams G&P Assets Rockies Greater Green River Powder River Appalachia Appalachia Mid-Con + Gulf Coast Gas-Directed Risked Reserves by Region (Tcf) 89% <$3.00/MMBtu HH 78% <$3.00/ MMBtu HH Piceance Denver- Julesburg Rockies 89% <$3.00/MMBtu HH 9 Legend Williams Assets Mid-Con + Gulf Coast Anadarko Permian Arkoma Haynesville Gas-directed Remaining Locations by Region Appalachia 84% <$3.00/ MMBtu HH 11.1K Barnett Mid-Con + Gulf Coast 82% <$3.00/ MMBtu HH 5.5K Eagle Ford Rockies 73% <$3.00/ MMBtu HH 1.5K Source: Wood Mackenzie NACPAT 4Q ,000 8,000 12,000 10

11 Natural gas provides superior economic and environmental benefits vs. other fuels, driving investment in new demand DECEMBER 2018 $/MMBTU BY FUEL SOURCE $12 $10 WTI to Henry Hub ratio 2.2X $61.00 Bbl $/MMBtu $8 $6 $4 Ethane Frac Spread 12 CPG 36 CPG $47.20 Bbl $52.16 Bbl $2 $0 $2.02 MMBTU Coal NYMEX $3.36 MMBTU Henry Hub Natural Gas Mt. Belvieu Ethane WTI Brent USGC NAPHTHA Sources: S&P Global Platts; NYMEX Note: Bar chart denotes MMBTU equivalent of quoted price; data label denotes quoted price 11

12 Robust domestic and global natural gas demand forecasts continue to rise, reaching 120 Bcf/d by 2023 NORTH AMERICAN NATURAL GAS DEMAND BY SECTOR ( ) 135 Bcf/d Demand Growth 17-18: 10% + ~1,045 Mbpd of incremental ethane represents ~2.9 Bcf/d of natural gas* Residential/ Commercial Power Generation Industrial Transport/ Other Mexico Exports LNG Exports North American demand growth increased by 4 Bcf/d from prior forecast Sources: Wood Mackenzie 1H 18; WMB Analytics; *Based off 90% utilization of announced North American ethane export capacity and North American ethylene plant capacity

13 Natural gas will continue to win global market share NATURAL GAS VS. OIL DEMAND GROWTH (2011 TO 2027); HENRY HUB AND WTI PRICES (MMBTU) Oil & Gas Price in MMBtu $18 $16 $14 $12 $10 $8 $6 $4 $2 $0 Forecast 45% 40% 35% 30% 25% 20% 15% 10% 5% 0% Cumulative Global Demand Growth Since 11 Cumulative Global Demand for Nat Gas Cumulative Global Demand for Oil Henry Hub Forward Curve WTI Forward Curve Sources: S&P Global Platts Analytics for global demand outlook; U.S. Energy Information Administration for price history; NYMEX for forward curves as of

14 U.S. natural gas market share increases over time for Power sector, while coal use declines; Contributes to a decline of CO2 emissions U.S. ELECTRIC POWER GENERATION AND EMISSIONS ,500 3,000 Electric Power (billion KWh) 4,000 3,500 3,000 2,500 2,000 1,500 1, ,500 2,000 1,500 1, Total Emission (MMt CO 2 ) Coal and petroleum power generation decreased by 40%, while natural gas power generation increased by 42% CO 2 emissions decline by 28% 0 0 Coal Natural Gas Renewables Nuclear Petroleum Total Emissions (MMT CO2) Note: Renewables = hydroelectric, wind, & solar power generation; Source: U.S. Energy Information Administration 14

15 Natural gas continues to be the preferred fuel type for new power generation projects in the United States, followed by renewables Natural Gas Wind Solar Nuclear Coal Other Power Generation Projects Under Construction by Fuel Type 0 5,000 10,000 15,000 20,000 Source: U.S. Energy Information Administration Nameplate Capacity (MW) Full bar represents nameplate capacity Dark blue represents expected utilization Fuel Type of Choice Partnering with Renewables > Carbon intensity from the U.S. power sector fell by 14% since 2005 as natural gas displaced other fossil fuels in power generation > Natural-gas fired power generation accounts for over 50% of current power projects under construction > As states make strides toward renewable power, it is vital for natural gas-fired generation to follow as a backup fuel to ensure grid reliability > Natural gas pipeline capacity is increasingly valuable as more capacity will be needed to support the intermittent nature of renewable power 15

16 Supply from advantaged basins must grow to meet forecasted demand NATURAL GAS FORECASTED PRODUCTION BY REGION & WELL TYPE ( ) Bcf/d Bcf/d or 61% +5.3 Bcf/d or 76% +3.0 Bcf/d or 35% +2.3 Bcf/d or 15% +2.0 Bcf/d or 46% Gas Directed Oil-Directed +1.9 Bcf/d or 33% -0.1 Bcf/d or -1% 70% of N.A. Gas growth comes from gas-directed drilling -0.5 Bcf/d or -30% 0 Northeast Permian Mid-con Western Canada Eagle Ford Haynesville + CV Rockies San Juan Note: Chart excludes Eastern Canada, Alaska, West Coast, Barnett, Gulf Coast conventional & GOM production that amounts to a decline of 2.4 Bcf/d through 2022; CV=Cotton Valley Source: Wood Mackenzie 1H 18 16

17 Forecasted Northeast production growth alone could fuel domestic natural gas demand growth through 2022 NORTH AMERICAN NATURAL GAS CUMULATIVE PRODUCTION GROWTH (IN BCF/D) NORTH AMERICAN NATURAL GAS CUMULATIVE DEMAND GROWTH (IN BCF/D) Exports Northeast is 60% of all North American gas production growth through 2022 Domestic Demand Northeast Permian All Other Res/Com Industrial Power Transport/Other LNG Exports Net Mexican Exports Source: Wood Mackenzie 1H 18 17

18 2 nd wave of U.S. LNG export projects expected to drive an additional +5 Bcf/d of growth through 2027 Williams Asset Map + Third-party Liquefaction Plants Sabine Pass Cove Point Corpus Christi Cameron Elba Island Freeport 2nd Wave Gulf Coast Golden Pass Woodfibre LNG Canada Prior 1H '17 Forecast 18,000 Forecasted Monthly LNG Export Volumes In MMcf/d 16,000 14,000 LNG export volumes to grow by +11 Bcf/d along Transco states through ,000 10,000 8,000 6,000 4,000 2,000 0 Source: Wood Mackenzie 1H 18 18

19 Global LNG demand grows by 24 Bcf/d through 2027, driven by Asia and Europe TOP DRIVERS OF GLOBAL LNG DEMAND BY COUNTRY Factors Driving Growth Bcf/d Global Market Reaching 63 Bcf/d Asia Europe Other Bcf/d China & India Developing economies pursuing clean energy for growth & fuel diversity Northwest Europe LNG balances the market with flexible, dependable supply Upside potential from weather events & other price sensitive demand responses Southeast Asia Need for supplemental supplies to replace maturing and declining indigenous resources Stronger growth prospects linked with better than anticipated economic developments Southeast Europe LNG complements domestic & pipeline supply Japan, South Korea & Taiwan While solely dependent on LNG, legacy importers expected to have flat to declining demand due to relatively mature energy demand market Source: Wood Mackenzie LNG Tool 3Q 18 19

20 Chinese LNG demand surpassed industry expectations in 2017; Growth outlook remains strong for 2018 and beyond Bcf/d Chinese LNG Demand vs. N.A. LNG Export Forecast China LNG Imports North America LNG Exports Factors Driving LNG Demand Growth in China Ambitious goals to improve air quality including almost doubling the share of gas in China s energy mix to 10% by 2020 Coal-to-gas switching to fight greenhouse gas emissions as natural gas emits nearly 60% less CO2 per kwh than coal in power generation Progress in liberalizing natural gas to allow nongovernment parties to receive access to pipelines and LNG terminals Short-term gas shortages due to peaked demand, lack of storage capacity and overstretched LNG infrastructure with a 2017 average utilization rate of 105% Declines in piped gas supply from central Asia and insufficient domestic gas production; unable to meet demand growth Sources: 1 Wood Mackenzie LNG Tool 3Q 18 and 1H 18 LT; 2 Columbia SIPA Center on Global Energy Policy 20

21 Williams best positioned to capitalize on significant opportunities to connect low-cost supplies to premier demand markets Production and Demand Growth in Key Areas in Bcf/d ( ) Northeast Demand Majority of production growth in Northeast with significant growth also occurring in the Permian Northeast Production +1.1 Williams assets uniquely aligned with demand growth along the East Coast from Texas all the way to the Northeast Permian Production Gulf Coast Demand +2.2 Southeast Demand LNG Exports (Elba + Cove Point) Leveraging significant investments in Northeast and Transco to connect best supplies to the best markets +2.1 Mexican Exports +6.9 GC LNG Exports Source: Wood Mackenzie 1H 18 Note: All other NA production amounts to 0.2 Bcf/d of growth and all other NA demand amounts to 1.6 Bcf/d of growth

22 Attractive returns on visible growth capital focused on Transco and G&P projects in the Northeast, West and AG Deepwater SUPPLY DRIVEN > West DJ Processing Plants 200 MMcf/d (Ft. Lupton III) > Atlantic Gulf Deepwater Stampede > Northeast G&P Susquehanna Gathering Expansion 700 MMcf/d > West DJ Processing Plant 225 MMcf/d (Keenesburg I) > West Wamsutter High Point, Hansen Lake & Echo Springs G&P Expansions > West Niobrara Jackalope Gathering & Bucking Horse Processing 200 MMcf/d > Northeast G&P Rich Gas Growth Driving Oak Grove Expansions > Northeast G&P Oak Grove II, III 400 MMcf/d & Harrison Hub C3+ Pipeline > Northeast G&P Bradford & Utica Gathering Expansion > West DJ Processing Plant 225 MMcf/d (Keenesburg II) > Northeast G&P Susquehanna Gathering Expansion 800 MMcf/d > Atlantic Gulf Deepwater Buckskin > West DJ Processing Plants 225 MMcf/d (Milton I) > West DJ Processing Plants 225 MMcf/d (Milton II) > Northeast G&P Oak Grove IV 200 MMcf/d > Atlantic Gulf Deepwater Additional Tie-backs: Shell Whale, Ballymore, Tigris, Mexico Perdido & others > Atlantic Gulf Deepwater Shell Appomattox Norphlet Pipeline Mobile Bay Gas Plant Expansion DEMAND DRIVEN > Transco Atlantic Sunrise 1.7 MMDth/d > West North Seattle Lateral Upgrade 159 MDth/d > Transco Rate Case > Transco Gulf Connector 475 MDth/d > Transco St. James Supply 162 MDth/d > Transco Rivervale S. to Market 190 Mdth/d > Transco Hillabee Phase MDth/d > Transco Southeastern Trail 296 MDth/d > Transco Gateway 65 MDth/d > Transco Northeast Supply Enhancement 400 MDth/d > Transco Leidy South 580 MDth/d > Transco Pursuing 20+ expansion opportunities including Project 1 from Analyst Day > Gulfstream Phase VI Expansion Black = In Progress; Blue = Potential/Under Negotiation 22

23 Atlantic Sunrise: Largest expansion project in Transco history placed in service October 6th delivers significant EBITDA growth > Significant revenue contribution to Transco $35 million/month (1) in consolidated fee-based revenue Williams U.S. Asset Map Highlighting Transco s Atlantic Sunrise Expansion Project OH PA NY NJ Atlantic Sunrise 1.7 MMDth/d > Northeast gas prices quickly respond to incremental takeaway capacity NE Gas prices rose from ~$1.20 to ~$2.70 the day Atlantic Sunrise was placed in service > Northeast G&P gathered volume and EBITDA uplift expected Price response supportive of producer activity in the NE PA Susquehanna 15% gathering volume growth CAGR expected EBITDA to grow at a higher rate due to improved operating margins WV $/MMBtu $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 Northeast Gas Prices Tetco M-2 TGP Z Leg Transco Leidy Atlantic Sunrise In Service Oct. 6 (1) Consolidated revenue will be reduced by lease payment of ~$8 million/month to partners 23

24 Transco: 2018 rate case protects adequate return on base system RATE CASE TIMELINE > Rate filed August 31, 2018 ~$270MM annual revenue increase Based on 16% ROE as prescribed by FERC methodology; every 1% change in ROE is worth ~$30MM in Revenue Subject to negotiation with shippers Proposed 5-year, $1.2B modernization and emission reduction investment program Rate increase and proposed modernization program incremental to 2019 guidance > Increased rates expected to be effective March 2019 RATE CASE CONSIDERATIONS > Lower corporate tax rate reduces income tax allowance > Factors driving higher cost of service Higher expense in recent years to be incorporated into rate case Maintenance capital and modernization spending to be reflected in rate base > By 2019 approximately 55% of fee revenues from negotiated rates Negotiated rate contracts remain unaffected by rate case and income tax changes VIRGINIA SOUTHSIDE II CONSTRUCTION Transco Pipeline, Southern Virginia 24

25 Transco Project 2 sanctioned: Leidy South Providing access to new Northeast supplies U.S. Map of Williams Assets, Highlighting Transco Pipeline PROJECT 1 > Extends Transco s reach Two examples of Transco s 20+ expansion opportunities > Greater than 1,000 MDth/d of firm transport capacity in Zones 3, 4, 5 and 6 > Attractive returns consistent with recent Transco expansions LEIDY SOUTH (PROJECT 2) > 580 MDth/d expansion in Pennsylvania from receipt points on Transco s Leidy system to Zone 6 markets > Target in-service date: 4Q 2021 > Target capital cost: $450-$550 million > 100% long-term, take-or-pay contracts providing attractive returns consistent with Transco s expansion project profile of ~6.4x > Provides transportation outlet for producers and supports incremental gathering volume for Williams Northeast PA gathering system 25

26 Transco: Unprecedented growth demonstrates competitive advantage TRANSCO CONTRACTED CAPACITY AND FEE-BASED REVENUE Contract Capacity MMDt/d Attractive Returns on Growth Projects 8.5 Growth Capital Placed In-service ($ Bln) Full-year run-rate Modified EBITDA ($ Bln) (1) (2) ~$1.4 ~$5.2 ~$0.24 ~$0.84 EBITDA multiple ~5.8x ~6.3x $2,750 $2,500 $2,250 $2,000 $1,750 $1,500 $1,250 $1,000 Fee Based Revenue, $ Millions Year-end Contracted Capacity Forecasted Year-end Contracted Capacity Fee Revenue ($ MM) Forecast Fee Rev. $750 (1) Includes Gulf Trace, Hillabee (Ph. 1), Dalton, NY Bay Expansion, Virginia Southside II, Garden State I (2) Includes Garden State II, Atlantic Sunrise, Gulf Connector, St. James Supply, Rivervale South to Market, NE Supply Enhancement, Hillabee (Ph. 2), Gateway, Southeastern Trail, Leidy South 26

27 Northeast G&P: Large footprint with foundational assets in place UTICA SUPPLY HUB (1) > Cardinal Gathering (3) > Flint Gathering > Utica East Ohio (UEO) (2) > 1.3 Bcf/d of gathering capacity in dry/rich gas > 800 MMcf/d of processing capacity > 135,000 bpd fractionation capacity BLUE RACER MIDSTREAM (2) > 570 miles of gathering pipeline in dry/rich gas > 800 MMcf/d of processing capacity > 123,000 bpd fractionation capacity > 151 miles of NGL and condensate transport (1) Gathering and processing statistics for Utica Supply Hub do not include Blue Racer (2) Non-operated joint venture (3) Primarily Cost-of-service based contracts PA SUSQUEHANNA SUPPLY HUB > 3.6 Bcf/d of gathering capacity in dry gas BRADFORD SUPPLY HUB (3) > 3.2 Bcf/d of gathering capacity in dry gas OHIO RIVER SUPPLY HUB > Ohio Valley Midstream > Laurel Mtn Midstream > Marcellus South > 1.5 Bcf/d of gathering capacity in dry/rich gas > 700+ MMcf/d processing capacity > 120,000+ bpd fractionation and deethanization capacity 27

28 Northeast G&P: Substantial growth expected from incremental takeaway capacity and new expansion projects to relieve constraints NORTHEAST GATHERING VOLUME GROWTH THROUGH 3Q 2018; AVERAGE GATHERED VOLUMES (BCF/D) 8 7 Legend Dry Gas Wet Gas 6 Bcf/d % GATHERED VOLUME CAGR EXPECTED Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q Notes: Partially owned system volumes are shown at 100%. Excludes volumes for all non-operated assets. 28

29 Gulf of Mexico: Substantial discoveries in close proximity to existing assets expected to facilitate long-term growth TX LA MS AL NORPHLET PIPELINE FL Gulf East 7 tiebacks contracted, expecting more Shell Appomattox dedication, Norphlet pipeline option Producer expected reserves: 650 MMboe Producer expected peak production: 175 Mboe/d Target in-service date: Mid 2019 Opportunities include Chevron/Total Ballymore discovery 3 miles from Blind Faith Largest discovery by Total in the GOM, with more than 670 ft of net oil pay TIGRIS ANCHOR BALLYMORE APPOMATTOX Discovery >1 TCF of gas discoveries within reach of KCC Buckskin, Stampede dedications Combined additional reserves: 66 Bcf Stampede online May Buckskin target in-service date: 2H 2019 Opportunities include discoveries at Anchor, Shenandoah and Katmai WHALE BUCKSKIN Gas Gathering Oil Gathering Norphlet Pipeline Deepwater Spar Growth Projects Mexico Deepwater Basin Gulf West Only existing Oil & Gas pipelines near active Western Gulf exploration Opportunities include Shell Whale (15 miles from existing pipelines), Tigris, and Mexico Perdido discoveries Shell Whale: One of Shell s largest finds in the GOM in the past decade, with over 1,400 feet of oil pay Sources: Chevron 1/30/2018 Ballymore Press Release, Total 1/31/2018 Ballymore Press Release, Shell 1/31/2018 Whale Press Release 29

30 Pro-forma Four Corners sale and DJ Basin acquisition: Fee-based business structure reinforces stability in cash flows ~97% of 2019 Gross Margin from Fee-based Sources 2019 Gross Margin (1) 3% NGL and Other Commodity Exposure > Reduced commodity exposure with sale of Four Corners Area assets 36% Volume-driven Non-regulated Fee-based Revenue > Volume-driven fee-based contracts for gathering, processing or other non-regulated services > Some contracts include escalation provisions 36% 3% 23% 38% 38% Regulated Gas Pipeline Fee-based Revenue > Fully contracted demand charge revenue > Attractive positions exposed to growth 23% Volume-protected Non-regulated Fee-based Revenue > Mix of capacity payments, MVCs (2) and Cost of Service agreements (1) Includes our proportional ownership of the gross margin of our equity method investments. Excludes certain regulated revenues, which are related to tracked operating costs. (2) MVC revenue includes revenue level guaranteed by MVC and excludes any revenue on volumes exceeding MVC. MVC revenue also includes amortization of upfront payments associated with canceled MVCs. 30

31 Moved to investment grade on significant credit metric improvement; Industry leading dividend coverage funding growth capital forecast >$4.4 billion of asset sales from significantly reducing our direct commodity exposure Jan. 17 repositioning and deleveraging transactions Streamlining the organization and aggressively managing costs No equity issuance required to fund forecasted growth capital Excess cash available after dividends and asset sales to be used to partially fund growth capex Capital discipline focused on ROCE (1) Debt / Adjusted EBITDA 6.50x 6.00x 5.50x 5.00x 4.50x 4.00x 3.50x 3.00x 5.97x 5.30x 4.62x ~5.00x GUIDANCE <4.75x ,500 5,000 4,500 4,000 3,500 3,000 2,500 Adjusted EBITDA ($ Millions) Long-term Target <4.2x Book Debt / Adjusted EBITDA $4.0 $3.5 $3.0 $2.5 $2.0 $1.5 $1.0 $0.5 ($ in billions) $3.9 Growth Capex $1.302 Cash from sale of Four Corners Area assets and Gulf Coast Pipelines $1.045 Excess Cash Available After Dividends $2.6 Growth Capex $1.25 Excess Cash Available After Dividends WMB Debt/Adjusted EBITDA Adjusted EBITDA ($MM) (1) WMB 2018 Debt/Adjusted EBITDA proforma for full year Atlantic Sunrise revenue contributions $ Note: This slide contains non-gaap financial measures. A reconciliation of all non-gaap financial measures used in this presentation to their nearest GAAP comparable financial measures are included at the back of this presentation. (1) Debt / Adjusted EBITDA ratios presented here does not represent leverage ratios measured for WMB credit agreement compliance or leverage ratios as calculated by the major credit ratings agencies. 31

32 Steady and predictable growth despite assets sales and commodity price volatility $/Share $1.10 $1.00 $0.90 $0.80 $0.70 $0.60 $0.50 Assets sales of over $3.4B Geismar in 17; Four Corners & Gulf Pipes in 18 (Note ~$2B in book gains are removed from Adjusted EPS) $0.63 Williams Adjusted EPS We expect 2018 to be in the upper half of our guidance range ($0.76 to $0.82) High Midpoint $0.82 High Midpoint $1.01 $0.89 $0.76 Low $0.77 $0.40 $0.30 $ Guidance Ranges 2019 Guidance Ranges Note: This slide contains non-gaap financial measures. A reconciliation of all non-gaap financial measures used in this presentation to their nearest GAAP financial measures is included at the back of this presentation. 32

33 Strong, stable and growing: 2018 and 2019 key guidance metrics 2018 GUIDANCE GUIDANCE Net Income $ $1.175 Bn $ $1.350 Bn Adjusted EBITDA $ $4.650 Bn $ $5.150 Bn Distributable Cash Flow (DCF) $ $2.900 Bn $ $3.300 Bn Expected Dividend Growth Rate Dividend Coverage Ratio 10-15% annual growth (annual dividend increases) ~1.6x Midpoint of Guidance 10-15% annual growth (annual dividend increases) ~1.7x Midpoint of Guidance Growth Capex $3.9 Bn $2.6 Bn Consolidated Debt / Adjusted EBITDA 2 ~ 5.0 x < 4.75x Note: This slide contains non-gaap financial measures. A reconciliation of all non-gaap financial measures used in this presentation to their nearest GAAP comparable financial measures are included at the back of this presentation. Williams does not expect to be a U.S. Federal cash income taxpayer through at least 2024, excluding taxes on any potential asset monetizations. 1 DCF shown Proforma as if the WPZ transaction had occurred 1/1/18. Dividend payments used in the coverage calculation include WPZ distribution payments to WPZ public unitholders for 1Q and 2Q. 2 Consolidated Debt / Adjusted EBITDA ratio does not represent leverage ratios measured for either WMB or WPZ credit agreement compliance or leverage ratios as calculated by the major credit ratings agencies. 33

34 Williams is a unique large-scale, low-volatility, growing natural gas infrastructure company with strong investor upside STABILITY > Volume-driven, natural gas strategy drives low volatility in earnings and cash flow > Advantaged and irreplaceable asset base handling 30% of U.S. low-cost natural gas supplies > Large-scale energy company: ~$52 billion enterprise value with Investment Grade credit ratings > 2019 gross margin projected to be ~97% fee-based > Met or exceeded Adjusted EBITDA street consensus each of the last 11 quarters (1) > Exceeded midpoint for 2017 key guidance metrics; 2018 trending toward high end of range > ~$1.25 billion excess cash available after dividends in 2019 WMB Median S&P 500 WMB vs. S&P 500 Approximate Current Dividend 5.8% 2.2% 163.6% Yield (2) GROWTH > Nation s largest and fastest growing interstate natural gas pipeline system, Transco, with unrivaled proximity to growing Mid-Atlantic, Southeast and Gulf Coast demand centers > 15% Northeast G&P gathered volume CAGR expected Adjusted EPS CAGR (2) ( ) 18.9% 13.6% 39.0% > 18.9% Adjusted EPS growth CAGR expected despite $3.4B in asset sales VALUATION > 10% Adjusted EBITDA growth ; expecting 5-7% annual Adjusted EBITDA growth longer term beyond 2019 > Attractive current dividend yield of 5.8% (2) with strong coverage > 10.4x EV / 2019 EBITDA multiple (2) below long-term historical average of 12.8x (3) > Long-term historical 12.8x multiple (3) implies a $34 stock price which aligns with sell-side consensus target price, providing for 44% upside to current price (2) Adjusted EBITDA Growth (2) ( ) Dividend Growth (2) ( ) 9.9% 7.1% 39.4% 12.5% 6.7% 86.6% (1) Per S&P Capital IQ, Williams adjusted EBITDA exceeded or was within 2% of the consensus estimate for EBITDA in each quarter 1Q Q (2) Data and estimates as of January 4, Median S&P growth rates based on Bloomberg consensus estimates. WMB growth rates based on midpoint of guidance. (3) Represents peer average EV / NTM EBITDA multiple from January 1, 2013 to current; peers include ENB, EPD, ET, KMI, OKE, TRGP, and TRP Note: This slide contains non-gaap financial measures. A reconciliation of all non-gaap financial measures used in this presentation to their nearest GAAP comparable financial measures are included at the back of this presentation. 34

35 Forward Looking Statements 35

36 FORWARD-LOOKING STATEMENTS Forward-looking statements > The reports, filings, and other public announcements of The Williams Companies, Inc. (Williams) may contain or incorporate by reference statements that do not directly or exclusively relate to historical facts. Such statements are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended (Securities Act), and Section 21E of the Securities Exchange Act of 1934, as amended (Exchange Act). These forwardlooking statements relate to anticipated financial performance, management s plans and objectives for future operations, business prospects, outcome of regulatory proceedings, market conditions, and other matters. We make these forward-looking statements in reliance on the safe harbor protections provided under the Private Securities Litigation Reform Act of All statements, other than statements of historical facts, included herein that address activities, events or developments that we expect, believe or anticipate will exist or may occur in the future, are forward-looking statements. Forwardlooking statements can be identified by various forms of words such as anticipates, believes, seeks, could, may, should, continues, estimates, expects, forecasts, intends, might, goals, objectives, targets, planned, potential, projects, scheduled, will, assumes, guidance, outlook, in-service date or other similar expressions. These forward-looking statements are based on management s beliefs and assumptions and on information currently available to management and may include, among others, statements regarding: Levels of dividends to Williams stockholders; Future credit ratings of Williams, and its affiliates; Amounts and nature of future capital expenditures; Expansion and growth of our business and operations; Expected in-service dates for capital projects; Financial condition and liquidity; Business strategy; Cash flow from operations or results of operations; Seasonality of certain business components; Natural gas and natural gas liquids prices, supply, and demand; Demand for our services. 36

37 FORWARD-LOOKING STATEMENTS Forward-looking statements (cont d) > Forward-looking statements are based on numerous assumptions, uncertainties and risks that could cause future events or results to be materially different from those stated or implied herein. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from results contemplated by the forward-looking statements include, among others, the following: Whether we are able to pay current and expected levels of dividends; Whether we will be able to effectively execute our financing plan; Availability of supplies, market demand, and volatility of prices; Inflation, interest rates, and general economic conditions (including future disruptions and volatility in the global credit markets and the impact of these events on customers and suppliers); The strength and financial resources of our competitors and the effects of competition; Whether we are able to successfully identify, evaluate and timely execute our capital projects and other investment opportunities; Our ability to acquire new businesses and assets and successfully integrate those operations and assets into existing businesses as well as successfully expand our facilities, and to consummate asset sales on acceptable terms; Development and rate of adoption of alternative energy sources; The impact of operational and developmental hazards and unforeseen interruptions; The impact of existing and future laws and regulations (including but not limited to the Tax Cuts and Jobs Act of 2017), the regulatory environment, environmental liabilities, and litigation, as well as our ability to obtain necessary permits and approvals, and achieve favorable rate proceeding outcomes; Our costs and funding obligations for defined benefit pension plans and other postretirement benefit plans; Changes in maintenance and construction costs; Changes in the current geopolitical situation; Our exposure to the credit risk of our customers and counterparties; Risks related to financing, including restrictions stemming from debt agreements, future changes in credit ratings as determined by nationally-recognized credit rating agencies and the availability and cost of capital; The amount of cash distributions from and capital requirements of our investments and joint ventures in which we participate; 37

38 FORWARD-LOOKING STATEMENTS Forward-looking statements (cont d) Risks associated with weather and natural phenomena, including climate conditions and physical damage to our facilities; Acts of terrorism, cybersecurity incidents, and related disruptions; Additional risks described in our filings with the Securities and Exchange Commission (SEC). > Given the uncertainties and risk factors that could cause our actual results to differ materially from those contained in any forward-looking statement, we caution investors not to unduly rely on our forward-looking statements. We disclaim any obligations to and do not intend to update the above list or announce publicly the result of any revisions to any of the forward-looking statements to reflect future events or developments. > In addition to causing our actual results to differ, the factors listed above may cause our intentions to change from those statements of intention set forth herein. Such changes in our intentions may also cause our results to differ. We may change our intentions, at any time and without notice, based upon changes in such factors, our assumptions, or otherwise. > Because forward-looking statements involve risks and uncertainties, we caution that there are important factors, in addition to those listed above, that may cause actual results to differ materially from those contained in the forward-looking statements. For a detailed discussion of those factors, see Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K filed with the SEC on February 22, 2018 and in Part II, Item 1A. Risk Factors in our Quarterly Reports on Form 10-Q. 38

39 Non-GAAP Reconciliations 39

40 NON-GAAP RECONCILIATIONS Non-GAAP Disclaimer > This presentation may include certain financial measures adjusted EBITDA, adjusted income ( earnings ), adjusted earnings per share, distributable cash flow and dividend coverage ratio that are non-gaap financial measures as defined under the rules of the Securities and Exchange Commission. > Our segment performance measure, modified EBITDA is defined as net income (loss) before income (loss) from discontinued operations, income tax expense, net interest expense, equity earnings from equity-method investments, other net investing income, remeasurement gain on equity-method investment, impairment of equity investments and goodwill, depreciation and amortization expense, and accretion expense associated with asset retirement obligations for nonregulated operations. We also add our proportional ownership share (based on ownership interest) of modified EBITDA of equity-method investments. > Adjusted EBITDA further excludes items of income or loss that we characterize as unrepresentative of our ongoing operations. Management believes this measure provides investors meaningful insight into results from ongoing operations. > Distributable cash flow is defined as adjusted EBITDA less maintenance capital expenditures, cash portion of net interest expense, income attributable to noncontrolling interests and cash income taxes, and certain other adjustments that management believes affects the comparability of results. Adjustments for maintenance capital expenditures and cash portion of interest expense include our proportionate share of these items of our equity-method investments. We also calculate the ratio of distributable cash flow to the total cash dividends paid (dividend coverage ratio). This measure reflects Williams distributable cash flow relative to its actual cash dividends paid. > This presentation is accompanied by a reconciliation of these non-gaap financial measures to their nearest GAAP financial measures. Management uses these financial measures because they are accepted financial indicators used by investors to compare company performance. In addition, management believes that these measures provide investors an enhanced perspective of the operating performance of assets and the cash that the business is generating. > Neither adjusted EBITDA, adjusted income, nor distributable cash flow are intended to represent cash flows for the period, nor are they presented as an alternative to net income or cash flow from operations. They should not be considered in isolation or as substitutes for a measure of performance prepared in accordance with United States generally accepted accounting principles. 40

41 NON-GAAP RECONCILIATIONS Reconciliation of Income (Loss) Attributable to The Williams Companies, Inc. to Adjusted Income (Dollars in millions, except per-share amounts) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr Year Income (loss) attributable to The Williams Companies, Inc. available to common stockholders $ 373 $ 81 $ 33 $ 1,687 $ 2,174 $ 152 $ 135 $ 129 $ 416 Income (loss) - diluted earnings (loss) per common share $.45 $.10 $.04 $ 2.03 $ 2.62 $.18 $.16 $.13 $.46 Adjustments: Northeast G&P Share of impairment at equity-method investments $ $ $ 1 $ $ 1 $ $ $ $ Impairment of certain assets Ad valorem obligation timing adjustment 7 7 Settlement charge from pension early payout program 7 7 Organizational realignment-related costs Total Northeast G&P adjustments Atlantic-Gulf Constitution Pipeline project development costs Settlement charge from pension early payout program Regulatory adjustments resulting from Tax Reform (20) (9) Benefit of regulatory asset associated with increase in Transco s estimated deferred state income tax rate following WPZ Merger (3) (3) Share of regulatory charges resulting from Tax Reform for equity-method investments Organizational realignment-related costs (Gain) loss on asset retirement (5) 5 (10) (10) Total Atlantic-Gulf adjustments (19) (12) (16) West Estimated minimum volume commitments (48) Impairment of certain assets 1, ,030 Settlement charge from pension early payout program Organizational realignment-related costs Regulatory adjustments resulting from Tax Reform (7) (7) Charge for regulatory liability associated with the decrease in Northwest Pipeline s estimated deferred state income tax rates following WPZ Merger Gains from contract settlements and terminations (13) (2) (15) Total West adjustments , ,256 (7)

42 NON-GAAP RECONCILIATIONS Reconciliation of Income (Loss) Attributable to The Williams Companies, Inc. to Adjusted Income (con t) (Dollars in millions, except per-share amounts) 1st Qtr 2nd Qtr 3rd Qtr 4th Qtr Year 1st Qtr 2nd Qtr 3rd Qtr Year Other (Gain) loss related to Canada disposition (2) (1) Expenses associated with strategic asset monetizations Geismar Incident adjustments (9) 2 8 (1) Gain on sale of Geismar Interest (1,095) (1,095) Gain on sale of RGP Splitter (12) (12) Accrual for loss contingency 9 9 Severance and related costs ACMP Merger and transition costs Expenses associated with Financial Repositioning (Gain) loss on early retirement of debt (30) 3 (27) 7 7 Impairment of certain assets Expenses associated with strategic alternatives Settlement charge from pension early payout program Regulatory adjustments resulting from Tax Reform Benefit of regulatory assets associated with increase in Transco s estimated deferred state income tax rate following WPZ Merger (45) (45) WPZ Merger costs Charitable contribution of preferred stock to Williams Foundation Total Other adjustments (13) 29 (999) 111 (872) Adjustments included in Modified EBITDA (5) , Adjustments below Modified EBITDA Gain on disposition of equity-method investment (269) (269) Accelerated depreciation by equity-method investments 9 9 Change in depreciable life associated with organizational realignment (7) (7) Gain on deconsolidation of Jackalope interest (62) (62) Allocation of adjustments to noncontrolling interests 77 (10) (28) (199) (160) (5) (199) (10) (28) (190) (427) (5) (41) (46) Total adjustments (204) Less tax effect for above items 77 (17) (55) (246) (241) (3) (3) (1) (7) Adjustments for tax-related items (1) (127) (1,923) (2,050) Adjusted income available to common stockholders $ 119 $ 108 $ 124 $ 170 $ 521 $ 159 $ 143 $ 243 $ 545 Adjusted diluted earnings per common share (2) $.14 $.13 $.15 $.20 $.63 $.19 $.17 $.24 $.61 Weighted-average shares - diluted (thousands) 826, , , , , , ,107 1,026, ,322 (1) The first quarter of 2017 includes an unfavorable adjustment related to the release of a valuation allowance. The fourth quarter of 2017 includes an unfavorable adjustment to reverse the tax benefit associated with remeasuring our deferred tax balances at a lower corporate rate resulting from Tax Reform. The third quarter of 2018 reflects tax adjustments driven by the WPZ Merger, primarily a valuation allowance for foreign tax credits. (2) The sum of earnings per share for the quarters may not equal the total earnings per share for the year due to changes in the weighted-average number of common shares outstanding. 42

43 NON-GAAP RECONCILIATIONS Reconciliation of Income (Loss) Attributable to The Williams Companies, Inc. to Adjusted Income (con t) (Dollars in millions, except per-share amounts) G U I D A N C E R A N G E S Midpt. High Low Midpt. High Net income (loss) $1,385 $1,460 $1,050 $1,200 $1,350 Less: Net income (loss) attributable to noncontrolling interests Net income (loss) attributable to The Williams Companies, Inc. 1,060 1, ,085 1,235 Adjustments 1 : Adjustments included in Modified EBITDA 2 (521) (521) Adjustments below Modified EBITDA (62) (62) Allocation of adjustments to noncontrolling interests Total adjustments (567) (567) Less tax effect for above items Adjustments for tax-related items Adjusted income available to common stockholders $744 $799 $935 $1,085 $1,235 Adjusted diluted earnings per common share $0.76 $0.82 $0.77 $0.89 $1.01 Weighted-average shares - diluted (millions) ,217 1,217 1,217 Note: Reconciliation shown with acquisition of WPZ completed on August 10, 2018 (1) A detailed list of adjustments is included in this presentation (2) Primarily a $593 million gain on the sale of Four Corners assets (3) Reflects tax adjustments driven by the WPZ Merger, primarily a valuation allowance for foreign tax credits 43

44 NON-GAAP RECONCILIATIONS Reconciliation of Income (Loss) Attributable to The Williams Companies, Inc. to Adjusted Income (con t) 2018 Guidance (Dollars in millions, except per-share amounts) Midpoint High Income (loss) attributable to The Williams Companies, Inc. available to common stockholders $1,060 $1,115 Income (loss) - diluted earnings (loss) per common share $1.09 $1.14 Adjustments: Northeast G&P Total Northeast G&P adjustments Atlantic-Gulf Constitution Pipeline project development costs 4 4 Regulatory adjustments resulting from Tax Reform (9) (9) Benefit of regulatory asset associated with increase in Transco s estimated deferred state income tax rate following WPZ Merger (3) (3) Share of regulatory charges resulting from Tax Reform for equity-method investments 2 2 (Gain) loss on asset retirement (10) (10) Total Atlantic-Gulf adjustments (16) (16) West Gain on Sale of Four Corners assets (593) (593) Regulatory adjustments resulting from Tax Reform (7) (7) Charge for regulatory liability associated with the decrease in Northwest Pipeline s estimated deferred state income tax rates following WPZ Total West adjustments (588) (588) 2018 Guidance Adjustments (continued) Midpoint High Other (Gain) loss on early retirement of debt 7 7 Impairment of certain assets Regulatory adjustments resulting from Tax Reform 1 1 Benefit of regulatory assets associated with increase in Transco s estimated deferred state income tax rate following WPZ Merger (45) (45) WPZ Merger costs Charitable contribution of preferred stock to Williams Foundation Total Other adjustments Adjustments included in Modified EBITDA (521) (521) Adjustments below Modified EBITDA Gain on deconsolidation of Jackalope interest (62) (62) Allocation of adjustments to noncontrolling interests (46) (46) Total adjustments (567) (567) Less tax effect for above items Adjustments for tax-related items (1) Adjusted income available to common stockholders $744 $799 Adjusted diluted earnings per common share $0.76 $0.82 Weighted-average shares - diluted (millions) Note: Reconciliation shown with acquisition of WPZ completed on August 10, 2018 (1) Reflects tax adjustments driven by the WPZ Merger, primarily a valuation allowance for foreign tax credit 44