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  • 1. 2014 Analyst & Investor Day May 12, 2014 1 Strong. Innovative. Growing.
  • 2. Forward-Looking Statements This presentation contains forward-looking statements within the meaning of the federal securities laws. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. The future results of EnLink Midstream, LLC, EnLink Midstream Partners, LP and their respective affiliates (collectively known as “EnLink Midstream”) may differ materially from those expressed in the forward-looking statements contained throughout this presentation and in documents filed with the Securities and Exchange Commission (“SEC”). Many of the factors that will determine these results are beyond EnLink Midstream’s ability to control or predict. These statements are necessarily based upon various assumptions involving judgments with respect to the future, including, among others, drilling levels; the dependence on Devon Energy Corporation for a substantial portion of the natural gas that EnLink Midstream gathers, processes and transports; the risk that EnLink Midstream will not be integrated successfully or that such integration will take longer than anticipated; the possibility that expected synergies will not be realized, or will not be realized within the expected timeframe; EnLink Midstream’s lack of asset diversification; EnLink Midstream’s vulnerability to having a significant portion of its operations concentrated in the Barnett Shale; the amount of hydrocarbons transported in EnLink Midstream’s gathering and transmission lines and the level of its processing and fractionation operations; fluctuations in oil, natural gas and natural gas liquids (NGL) prices; construction risks in its major development projects; its ability to consummate future acquisitions, successfully integrate any acquired businesses, realize any cost savings and other synergies from any acquisition; changes in the availability and cost of capital; competitive conditions in EnLink Midstream’s industry and their impact on its ability to connect hydrocarbon supplies to its assets; operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond its control; and the effects of existing and future laws and governmental regulations, including environmental and climate change requirements and other uncertainties and other factors discussed in EnLink Midstream’s Annual Reports on Form 10-K for the year ended December 31, 2013, and in EnLink Midstream’s other filings with the SEC. You are cautioned not to put undue reliance on any forward-looking statement. EnLink Midstream has no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events or otherwise. 2
  • 3. Non-GAAP Financial Information This presentation contains non-generally accepted accounting principle financial measures that EnLink Midstream refers to as adjusted EBITDA, gross operating margin, segment cash flows, growth capital expenditures and maintenance capital expenditures. Adjusted EBITDA is defined as net income plus interest expense, provision for income taxes, depreciation and amortization expense, stock-based compensation, (gain) loss on noncash derivatives, transaction costs, distribution of equity investment and non-controlling interest; and income (loss) on equity investment. Gross operating margin is defined as revenue less the cost of purchased gas, NGLs, condensate and crude oil. Segment cash flows is defined as revenue less the cost of purchased gas, NGLs, condensate, crude oil and operating and maintenance expenditures. The amounts included in the calculation of these measures are computed in accordance with generally accepted accounting principles (GAAP) with the exception of maintenance capital expenditures. Growth capital expenditures are defined as all construction-related direct labor and material costs, as well as indirect construction costs including general engineering costs and the costs of funds used in construction. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of the assets and to extend their useful lives. EnLink Midstream believes these measures are useful to investors because they may provide users of this financial information with meaningful comparisons between current results and prior-reported results and a meaningful measure of EnLink Midstream’s cash flow after it has satisfied the capital and related requirements of its operations. Adjusted EBITDA, segment cash flows, gross operating margin, growth capital expenditures and maintenance capital expenditures, as defined above, are not measures of financial performance or liquidity under GAAP. They should not be considered in isolation or as an indicator of EnLink Midstream’s performance. Furthermore, they should not be seen as measures of liquidity or a substitute for metrics prepared in accordance with GAAP. 3
  • 4. Investor Notice The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC's definitions for such terms, and price and cost sensitivities for such reserves, and prohibits disclosure of resources that do not constitute such reserves. This presentation may contain certain terms, such as resource potential and exploration target size and risked resource. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized. The SEC guidelines strictly prohibit us from including these estimates in filings with the SEC. Investors are urged to consider closely the disclosure in Devon Energy Corporation’s Form 10-K, available at Devon Energy Corporation, Attn. Investor Relations, 333 West Sheridan, Oklahoma City, OK 73102-5015. You can also obtain this form from the SEC by calling 1-800-SEC-0330 or from the SEC’s website at www.sec.gov. 4
  • 5. Agenda & Speakers Roadmap for Growth • Barry Davis President & CEO • Michael Garberding EVP and CFO Devon Energy Sponsorship • John Richels Devon Energy Corporation, CEO Natural Gas Businesses • Steve Hoppe EVP, President of Gas Gath., Proc. & Trans. • Mike Burdett SVP of Commercial Development • Brad Iles SVP of Business Development • Stan Golemon SVP of Engineering Liquids Businesses • Mac Hummel EVP & President of NGL & Crude • Stan Golemon SVP of Engineering • Chris Tennant VP of NGL • Paul Weissgarber SVP of Ohio River Valley Financial Outlook • Michael Garberding EVP and CFO Non-Operated Investments • Brad Iles SVP of Business Development 5
  • 6. The Roadmap for Growth Barry E. Davis, President and Chief Executive Officer 6
  • 7. Management Team Experience Barry Davis President & CEO Barry Davis is President and Chief Executive Officer of EnLink Midstream. Mr. Davis led the founding of Crosstex Energy in 1996 prior to the initial public offerings of Crosstex Energy, L.P. in 2002 and Crosstex Energy, Inc. in 2004. Under his leadership, Crosstex evolved into a significant service provider in the energy industry’s midstream business sector. Joe Davis EVP & General Counsel Joe Davis is Executive Vice President and General Counsel of EnLink Midstream. Mr. Davis joined Crosstex Energy in 2005 after serving as a partner at Hunton & Williams, an international law firm, where he also was a member of the executive committee. Mr. Davis began his legal career at Worsham Forsythe, which merged with Hunton & Williams in 2001. Michael Garberding EVP & CFO Michael Garberding is Executive Vice President and Chief Financial Officer of EnLink Midstream. Previously, Mr. Garberding held various positions at Crosstex Energy, including Executive Vice President and Chief Financial Officer, and Senior Vice President of Business Development and Finance. Prior to joining Crosstex in 2008, Mr. Garberding was assistant treasurer at TXU Corp. where he focused on structured transactions such as project financing for coal plant development and the sale of TXU Gas Company. Steve Hoppe EVP & President of Gas Gathering, Processing and Transportation Steve Hoppe is Executive Vice President and President of the Gathering, Processing and Transportation Business of EnLink Midstream. Mr. Hoppe previously served as Vice President of Midstream Operations for Devon, which he joined in 2007. Prior to joining Devon, Mr. Hoppe spent eight years at Thunder Creek Gas Services, most recently serving as president. EnLink Midstream management team is comprised of former Crosstex and Devon senior management and other experienced midstream leaders McMillan (Mac) Hummel EVP & President of NGL and Crude Oil Mac Hummel is Executive Vice President and President of the Natural Gas Liquids and Crude Business of EnLink Midstream. Mr. Hummel previously served as Vice President of Commodity Services at Williams Companies Inc. since 2013, and prior to that he served as Vice President, NGLs & Olefins at Williams from 2010 to 2012. Mr. Hummel worked at Williams for 29 years. The Leadership: Experienced Management Team with a Proven Track Record 7
  • 8. EnLink Midstream Partners, LP Master Limited Partnership NYSE: ENLK (BBB / Baa3) EnLink Midstream, LLC General Partner NYSE: ENLC Public Unitholders ~70% ~30% ~1% GP ~7% LP EnLink Midstream Holdings (formerly Devon Midstream Holdings) ~52% LP ~40% LP 50% LP Devon Energy Corp. NYSE: DVN (BBB+ / Baa1) GP + 50% LP The Vehicle for Sustainable Growth: MLP Structure with a Premier Sponsor 8 Dist./Q Split Level < $0.2500 2% / 98% < $0.3125 15% / 85% < $0.3750 25% / 75% > $0.3750 50% / 50% Current Position ENLC owns 100% of IDRs ~50% LP
  • 9. Gathering System Processing Plant Fractionation Facility North Texas Systems Louisiana Gas System Louisiana NGL System Cajun-Sibon Expansion Howard Energy Ohio River Valley Pipeline Storage Crude & Brine Truck Station Brine Disposal Well Barge Terminal Rail Terminal Condensate Stabilizers (1) Increasing to 7 facilities with 252,000 Bbl/d of total net capacity upon completion of the Cajun-Sibon phase II expansion expected in the second half of 2014. AUSTIN CHALK EAGLE FORD PERMIAN BASIN CANA-WOODFORD ARKOMA- WOODFORD BARNETT SHALE HAYNESVILLE & COTTON VALLEY UTICA MARCELLUS LA TX OK OH WV PA The Vehicle for Sustainable Growth: Strategically Located and Complementary Assets Gas Gathering and Transportation  ~7,300 miles of gathering and transmission lines Gas Processing  12 plants with 3.3 Bcf/d of total net inlet capacity  1 plant with 60 MMcf/d of net inlet capacity under construction NGL Transportation, Fractionation and Storage  ~570 miles of liquids transport line  6 fractionation facilities with 180,000 Bbl/d of total net capacity(1)  3 MMBbl of underground NGL storage Crude, Condensate and Brine Handling  200 miles of crude oil pipeline  Barge and rail terminals  500,000 Bbl of above ground storage  100 vehicle trucking fleet  8 Brine disposal wells 9
  • 10. Jackfish Pike Granite Wash Barnett Shale Permian Basin Ferrier Corridor Cana Woodford Mississippian-Woodford Rockies Oil Greater Wapiti Washakie Carthage Groesbeck Access Pipeline Mississippian-Woodford Water Handling Ferrier Plant Rockies Midstream E. Texas Midstream Devon’s Upstream Portfolio & Non-Contributed Midstream Assets Horn River Oil Liquids-Rich Dry Gas Midstream Haynesville/Bossier The Vehicle for Sustainable Growth: Devon is Committed to the Success of EnLink Midstream  Devon has dedicated ~800,000 net acres to EnLink Midstream  Long-term contracts in place to stabilize future cash flows ̶ 10-year fixed-fee contracts with rate escalators ̶ 5-year minimum gathering commitments (>1.3 Bcf/d) ̶ 5-year minimum processing commitments (>1.0 Bcf/d)  Development of Devon’s upstream portfolio provides organic growth opportunities  Potential to acquire additional Devon midstream assets 10
  • 11. The Vehicle for Sustainable Growth: Diverse, Fee-Based Cash Flows  Devon is EnLink Midstream’s largest customer (>50% of consolidated 2014E adjusted EBITDA*)  EnLink Midstream’s growth projects focused on crude/NGL services and rich gas processing  Strong emphasis on fee-based contracts 2014E EnLink Midstream Consolidated Gross Operating Margin* 95% 5% By Contract Type Texas 57% 19% Ohio 5% Okla. 19% By Region 56% Devon 44% Other By Customer Fee-Based Commodity Sensitive * Gross operating margin and adjusted EBITDA percentage estimates are provided for illustrative purposes and reflect period following transaction closing (2Q-4Q 2014). Note: Adjusted EBITDA and gross operating margin are non-GAAP financial measures and are explained on page 3. Louisiana 11
  • 12. The Vehicle for Sustainable Growth: Strong Balance Sheet and Liquidity  Devon assets contributed with no debt  Investment grade balance sheet at ENLK (BBB / Baa3) provides low cost of capital  Long-term commitment to investment grade metrics (debt/adjusted EBITDA <3.5x)  Expected long-term distribution growth of high single digits at ENLK  Expected long-term distribution growth of 20% at ENLC  Combined Enterprise value of approximately $14 Billion ̶ LP Enterprise Value of ~$8 Billion ̶ GP Enterprise Value of ~$6 Billion 12
  • 13. Pipeline Infrastructure Capital Spending Needed Per Year in the U.S.* (2011 – 2035) $30.0 B $14.6 B $15.4 B Total Gas Liquids The Road Conditions: Exponentially Growing Energy Market 13* Source: INGAA Study Surging U.S. Production Requires the Re-Piping of America, With Expected Midstream Investment of $30 Billion Annually for 20+ years * * ***
  • 14. NYMEX Gas Breakeven Price ($/MMBtu) for 10% Return WTI Oil Breakeven Price ($/Bbl) for 15% IRR The Road Conditions: Presence in the Profitable Plays 14 Source: Credit Suisse; Natural Gas and Oil prices used for breakeven calculations are $4/MMBtu and $90/Barrel, respectively. Devon and EnLink Midstream Have Significant Presence in Most Prolific and Profitable Shale Plays $5.37 $5.05 $4.25 $4.13 $3.81 $3.75 $3.70 $3.66 $3.65 $3.34 $3.27 $3.26 $3.02 $2.94 $2.50 $2.47 $1.35 $0.62 $0.29 $0.00 $0.00 $0.00 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 Haynesville/Bossier Shale - NE… Woodford Shale - Arkoma Eagle Ford Shale - Dry Gas Haynesville Shale - Core LA / TX Piceance Basin Valley Pinedale Barnett Shale - Southern… Barnett Shale Horn River Basin Barnett Shale - Core Fayetteville Shale Marcellus Shale - SW Marcellus Shale - NE Cotton Valley Horizontal Cana Woodford Shale Granite Wash - Liquids Rich… Utica - Wet Gas Marcellus Shale - SW Liquids… Mississippian Horizontal - West Eagle Ford - Liquids Rich Utica - Liquids Rich Marcellus Shale - Super Rich $90.00 $84.45 $74.95 $73.10 $72.15 $68.77 $68.54 $68.52 $66.89 $64.74 $64.63 $64.05 $61.57 $61.57 $59.92 $58.48 $55.29 $55.02 $53.92 $46.10 $46.05 $44.04 $42.15 $32.39 $25.63 $24.23 $20 $40 $60 $80 $100 Cotton Valley Horizontal Barnett Shale - Southern… Uinta - Wasatch (V) Granite Wash - Liquids Rich Horiz. Uinta - Wasatch (H) Uinta - Green River Wolfcamp - N. Delaware… Bone Spring (3rd) - W TX Three Forks Bakken Shale Wolfberry Mississippian Horizontal - West Cana Woodford Shale Wolfcamp - S. Midland… Cana Woodford Shale - Oil… Yeso Eagle Ford - Oil Window Bone Spring (1st / 2nd) - NM Wolfcamp - N. Midland… Niobrara - Wattenberg Eagle Ford - Liquids Rich Utica - Liquids Rich Mississippian Horizontal - East Utica - Wet Gas Marcellus Shale - Super Rich Marcellus Shale - SW Liquids Rich EnLink and/or Devon assets are in these plays Neither EnLink nor Devon assets are in these plays
  • 15. North American Ethylene Plants & Capacities * ** South Louisiana: 10 Plants, 15.0 B Lb/Yr, ~25% of N.A. capacity 12.5% 4 Plants 8.6 B Lb/Yr 3.3% 2 Plants 2.3 B Lb/Yr 80% 33 Plants 56.1 B Lb/Yr** 3.6% 2 Plants 2.5 B Lb/Yr 0.6% 1 Plant 0.4 B Lb/Yr * Source: En*Vantage, April 2014; Chart represents the maximum capability to crack ethane at S. LA ethylene plants versus the maximum capability to extract ethane in Louisiana. 0 100 200 300 400 500 600 700 2012 2013 2014 2015 2016 2017 2018 2019 2020 New World-Scale Plant Conversions/Expansions/Restarts 2012 Ethane Cracking Capability LA Gulf Coast Ethane Extraction Capability South Louisiana Ethane Balances * The Road Conditions: Global Shift in Petrochemical Industry 15 U.S. Petrochemical Producers in Gulf Coast have tremendous demand for NGLs, and there is now a shortfall of locally produced supply in South Louisiana*
  • 16.  Near-term focus on platform expansion opportunities  Longer-term focus on pursuing scale positions in new basins, especially in areas where Devon is active  South Louisiana Liquids Expansions – Cajun-Sibon  West Texas Gas Expansions – Bearkat  Other focused areas for growth  Potential Areas where Devon Needs Infrastructure ̶ Eagle Ford ̶ Permian Basin ̶ Oklahoma ̶ New Basins Destination 2017: The Four Avenues for Growth 16  E2 dropdown  Dropdown of legacy Devon midstream assets at ENLC  Access Pipeline dropdown  Eagle Ford Victoria Express Pipeline dropdown Dropdown Opportunities Growing With Devon Organic Growth Projects Mergers & Acquisitions AVENUE 1 AVENUE 2 AVENUE 3 AVENUE 4
  • 17. Devon Energy Sponsorship John Richels, Chief Executive Officer of Devon Energy Corporation 17
  • 18. Devon Overview Sharpening The Focus 18 Devon’s Core & Emerging Assets Core Emerging Heavy Oil Rockies Oil Mississippian- Woodford Barnett Shale Permian Basin Anadarko Basin Eagle Ford (1) Excludes non-core assets identified for monetization.  Proved reserves: 2.6 billion BOE(1)  2014e net production: 580 – 620 MBOED(1) ̶ Expect multi-year oil growth >20% ̶ Oil & liquids ≈55% of 2014e production  Deep inventory of oil opportunities ̶ Top-tier Eagle Ford development ̶ Strong Permian Basin position ̶ World-class steam-assisted-gravity-drainage (“SAGD”) oil projects ̶ Upside potential in emerging plays  Midstream business valued at >$7 billion  Devon’s Enterprise Value: ≈$35 billion
  • 19. Sharpening The Focus Devon’s Recent Strategic Actions  Innovative midstream combination  Accretive Eagle Ford acquisition  Announced non-core asset sales 19
  • 20. Permian Basin 28% 21%21% 7% 5% 11% 2% 5% Note: Capital figures exclude capitalized G&A and interest, midstream and other corporate capital. For 2014, this represents approximately $1.4 billion. Key Highlights  Devon 2014 E&P capital expenditures: — “Go-forward” assets: $4.8 - $5.2 billion — $260 million attributable to non-core properties  Capital concentrated in oil development plays — “Go forward” assets delivering >70% growth in U.S. oil production — Long-term investment in Canadian oil growth — “Go forward” assets growing top-line production ≈10%  Total capital spend to remain within cash flow  JV carries minimize capital costs in emerging oil plays (>$1 billion of drilling carries in 2014) Devon’s 2014 Capital Budget $5.0 - 5.4 Billion Eagle Ford Heavy Oil Anadarko Basin Barnett Shale Emerging Oil Other Non-Core Assets 2014 E&P Capital Program Delivering Strong Oil Growth 20
  • 21. Permian Basin 2014 Focus Areas  Devon Net acreage: 1.3 million basin-wide with stacked-pay potential  Q4 2013 net production: 86 MBOED (≈60% oil)  Deep inventory of low-risk projects  Delivering highly economic & robust production growth — Expect ≈20% oil growth in 2014  Operated rig count: 23  2014 E&P capital: $1.5 billion  2014 plans: Drill ≈350 wells Midland Basin Northwestern Shelf Central Basin Platform Ozona ArchDiablo Platform NewMexico Texas Midland Wolfberry Conventional Wolfcamp Shale Eastern Shelf Bone Spring & Delaware TEXAS NEW MEXICO OKLAHOMA 21
  • 22. Eagle Ford World-Class Oil Asset  Located in best part of Eagle Ford  Devon Net acreage: 82,000 — Working interest: 50% — Net revenue interest: 38%  Acquisition closed on February 28th  2014e net production: 70 – 80 MBOED(1) — 57% Oil & Condensate — 19% NGLs — 24% Gas  Risked resource: ≈400 MMBOE  Drilling inventory: ≈1,200 locations  2014 E&P capital: $1.1 billion — Drill ≈200 wells Karnes Devon Acreage Gonzales DeWitt Lavaca TEXAS OKLAHOMA (1) Represents Devon’s average estimated net production from March through December 22
  • 23. Ft. McMurray Edmonton Calgary ALBERTABRITISH COLUMBIA Jackfish & Pike Jackfish 1 Jackfish 2 Jackfish 3 Access Pipeline R8 R7 R6 R5 R4 T76 T75 T74 T73 Jackfish Acreage (100% WI) Pike Acreage (50% WI) Access Pipeline (50% Ownership) Pike Project Area 6 Miles Jackfish 1  Facility running at peak capacity  Delivering top-tier operating results Jackfish 2  Q4 production increased >30% sequentially  New well pad ramping up Jackfish 3  Plant start-up expected in Q3 2014 Pike  Expect phase 1 sanctioning decision and regulatory approval in 2014 Heavy Oil – Jackfish & Pike SAGD Oil Development 23
  • 24. Net risked resource: >25 TCFE Risked locations: >10,000  Devon net acreage: >950,000  Low average royalty burden: <20%  Q4 2013 net production: 1.9 BCFED (30% liquids)  Significant free cash flow (≈$1 billion in 2014)  Operated rig count: 4  2014 E&P capital: $600 million  2014 plans: Drill ≈200 wells Basin Wheeler Hemphill Canadian Blaine Caddo Johnson Tarrant DentonWise Parker Ft. Worth Denton Oklahoma City Barnett Shale Net Acres: >600,000 Q4 Production: >1.3 BCFED Operated Rigs: 2 Anadarko Basin (Cana & Granite Wash) Net Acres: >350,000 Q4 Production: 512 MMCFED Operated Rigs: 2 Barnett Shale & Anadarko Basin Liquids-Rich Gas 24
  • 25. Mississippian-Woodford & Rockies Emerging Oil Opportunities Mississippian-Woodford  Multiple oil-bearing intervals  Best wells to-date: IP’s >1,000 BOED  Drilling activity focused on JV acreage  Improving consistency  Integration of 3D seismic will optimize  2014 E&P capital: ≈$300 million  2014 plans: Drill >200 wells Rockies Oil  Focused in the Powder River Basin  Stacked oil targets (Parkman, Turner, Frontier & others)  Best wells to-date: IP’s >1,000 BOED  2014 E&P capital: ≈$300 million  2014 plans: Drill ≈30 wells Rockies Oil Net Acres: 150,000 Q4 Production: 21 MBOED Operated Rigs: 3 Mississippian-Woodford Net Trend Acres: >600,000 Dec Net Production: 16,000 BOED Operated Rigs: 8 WYOMING OKLAHOMA 25
  • 26. Why EnLink Is Important to Devon  Devon retains majority ownership — GP (ENLC 70%) — MLP (ENLK 52%)  EnLink transaction highly accretive to shareholders — Initial transaction valued contributed assets at $4.8 billion  Market value of Devon’s EnLink ownership interest: >$7 billion  Improves capital efficiency, diversification, scale and growth of midstream business AUSTIN CHALK EAGLE FORD PERMIAN BASIN CANA-WOODFORD ARKOMA- WOODFORD BARNETT SHALE HAYNESVILLE & COTTON VALLEY UTICA MARCELLUS LA TX OK OH WV PA Gathering System Processing Plant Fractionation Facility North Texas Systems Louisiana Gas System Louisiana NGL System Cajun-Sibon Expansion Howard Energy Ohio River Valley Pipeline Storage Crude & Brine Truck Station Brine Disposal Well Barge Terminal Rail Terminal Condensate Stabilizers 26
  • 27. Potential Drop Down Asset Access Pipeline (SAGD Oil Midstream)  Three ≈180 mile pipelines from Sturgeon Terminal to Devon’s thermal acreage  ~30 miles of dual pipeline from Sturgeon Terminal to Edmonton  Devon ownership: 50%  Capacity net to Devon (after 2014 expansion): — Blended bitumen: 170 MBPD — Diluent: 95 MBPD  Expandable with additional investment  Access to Edmonton refining and rail, West Coast waterborne and U.S. markets  Flexibility enhances economics EDMONTON HARDISTY Express P/L To U.S. Rockies 16” Diluent Line (Edmonton to Jackfish Area) Oil Pipelines JACKFISH & PIKE Sturgeon Terminal 24” Diluent Line (Sturgeon to Jackfish Area) 42” Blend Line (Jackfish Area to Sturgeon) 30” Blend Line (Sturgeon to Edmonton) 27
  • 28. Potential Drop Down Asset Victoria Express Pipeline (VEX) (Eagle Ford)  ≈56 mile crude oil pipeline from Eagle Ford core to Devon’s Port of Victoria terminal  50 MBOPD start-up capacity (expandable for 3rd parties)  ≈300,000 barrels of storage available  VEX commissioning to begin early Q3  Provides additional market options for crude and condensate  Devon ownership: 100%  Total current project capital: $70 MM (≈1/2 of capital spent by GeoSouthern) Point Comfort Port of Victoria Karnes Gonzales DeWitt Lavaca Victoria Jackson Goliad Wharton Colorado Calhoun Refugio Aransas Matagorda VEX Potential Expansion VEX Under Construction Devon Acreage Gulf of Mexico 28
  • 29. Potential for additional midstream activity in:  Eagle Ford  Permian Basin  Oklahoma  New basins Other Potential Midstream Activity 29
  • 30. The Four Avenues for Growth Barry E. Davis, President & Chief Executive Officer Michael J. Garberding, EVP & Chief Financial Officer 30
  • 31.  Near-term focus on platform expansion opportunities  Longer-term focus on pursuing scale positions in new basins, especially in areas where Devon is active  South Louisiana Liquids Expansions – Cajun-Sibon  West Texas Gas Expansions – Bearkat  Other focused areas for growth  Potential Areas where Devon Needs Infrastructure ̶ Eagle Ford ̶ Permian Basin ̶ Oklahoma ̶ New Basins Destination 2017: The Four Avenues for Growth 31  E2 dropdown  Dropdown of legacy Devon midstream assets at ENLC  Access Pipeline dropdown  Eagle Ford Victoria Express Pipeline dropdown Dropdown Opportunities Growing With Devon Organic Growth Projects Mergers & Acquisitions AVENUE 1 AVENUE 2 AVENUE 3 AVENUE 4
  • 32. Avenue 1: Future Dropdowns Devon Sponsorship Creates Dropdown Opportunities 32 Estimated Capital Cost: $80 MM Estimated Cash Flow: ~$12 MM Estimated Capital Cost: $1.0 B Estimated Cash Flow: ~$150 MM Acquisition Cost: $2.4 B Estimated Cash Flow: ~$200 MM Estimated Capital Cost: $70 MM Estimated Cash Flow: ~$12 MM 2014 2015 2016 2017 Devon Sponsorship Provides Potential for ~$375 MM of Cash Flow from Dropdowns Other Potential Devon Dropdowns E2 Legacy Devon Midstream Assets Access Pipeline Victoria Express Pipeline Cautionary Note: The information on this slide is for illustrative purposes only. No agreements or understandings exist regarding the terms of these potential dropdowns, and Devon is not obligated to sell or contribute any of these assets to EnLink. The completion of any future dropdown will be subject to a number of conditions. The capital cost and cash flow information on this slide is based on management’s current estimates and current market information and is subject to change.
  • 33. Note: Capital spend figures exclude capitalized G&A and interest, midstream and other corporate capital. For 2014, this represents approximately $1.4 billion. Devon 2014 E&P Capital Budget $5.0 - 5.4 Billion Avenue 2: Growing With Devon Serving Devon’s Needs is a Priority  Devon has significant financial incentive to contract midstream development with EnLink ̶ 70% ownership of ENLC, 52% ownership of ENLK ̶ Once EnLink enters the 50% level of the splits, approximately $0.60 of each incremental $1.00 distributed by EnLink goes to Devon  Devon has historically spent $350-$700 MM annually on midstream capital expenditures 28% 21%21% 7% 5% 11% 2% 5% Permian Basin Eagle Ford Heavy Oil Anadarko Basin Barnett Shale Emerging Oil Other Non-Core Assets $0 $100 $200 $300 $400 $500 $600 $700 $800 2011 2012 2013 2014E Devon Historical Midstream Capital Expenditures ($MM) 33
  • 34. Avenue 3: Organic Growth Significant Organic Growth Projects Already Underway 34 South Louisiana Platform Expansion • Focused on bolt-on expansions around premier South Louisiana liquids position • Cajun-Sibon expansion expected to be operational in 2014 • Increasing utilization of existing NGL asset base West Texas Platform Expansion 3rd Party Growth Around Legacy Devon Midstream Assets • Significant bolt-on expansion opportunities around Cana-Woodford and Barnett Shale assets • Commercial teams currently in discussions with various potential producers Expand Canadian Oil Sands Presence • Access Pipeline creates platform for significant growth in Alberta Canada • Will have commercial teams looking at additional expansions and services • Focused on providing associated gas processing and high pressure gathering services • Bearkat plant and high pressure gathering pipelines expected to be complete in 2014 • Excess pipeline capacity opportunity for continued growth
  • 35. Avenue 4: Mergers & Acquisitions  Near-term focus on platform expansion opportunities  Longer-term focus on pursuing scale positions in new basins, especially in areas where Devon is active  Superior financing capabilities already in place ̶ Low cost of capital with investment grade balance sheet (BBB / Baa3) ̶ Significant flexibility with approximately $1.0 billion of liquidity at ENLK  Potential to pursue strategic acquisitions jointly with Devon 35
  • 36. EnLink Midstream Today & Tomorrow EnLink Midstream Today EnLink Midstream Potential Future in 2017 36 South Louisiana Growth: Cajun-Sibon West Texas Growth: Bearkat Victoria Express Dropdown Complete E2 Dropdown Complete Other Potential Step Changes Other Growth Factors • Growth from Serving Devon • Mergers & Acquisitions Potential for $375 MM of Additional Cash Flows from dropdowns Heavy Oil Access Pipeline Dropdown Complete CANADIAN OIL SANDS Significant Organic Growth Projects Underway Midstream Holdings Dropdown Complete
  • 37. Natural Gas Assets Steve Hoppe, EVP, President of Gathering, Processing and Transportation Mike Burdett, SVP of Commercial Development Brad Iles, SVP of Business Development Stan Golemon, SVP of Engineering 37
  • 38. Natural Gas Gathering, Processing and Transportation Business Unit $126 $114 North Texas  Gas gathering  Gas processing & NGL fractionation  Condensate stabilization  Gas Transportation Oklahoma  Gas gathering  Gas processing  Condensate stabilization West Texas  Gas gathering  Gas processing & NGL fractionation Gas Business Unit Q2-Q4 2014 Forecasted Segment Cash Flow: ~ $420 MM * Gas 76% 38 Liquids 24% * Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 39. Devon Contracts Provide Cash Flow Stability in North Texas and Oklahoma  Term: 10 year initial term (acreage dedication), year-to-year thereafter; 5 year minimum volume commitment  Financial terms: Per-MMbtu fees for gathering and processing with CPI escalator  Volume Commitment: Approximately 88% of expected volumes for the 12 months ending 9/30/2014  Gathering and Processing Obligation: EnLink Midstream obligated to gather and process on a firm basis  Downstream Marketing: Devon is responsible for nominations and scheduling of redelivered residue gas, condensate and NGLs  Well Connections: EnLink Midstream is responsible for connecting wells located within three miles of the pipeline system at its cost; at greater than three miles, EnLink Midstream has the right, but not the obligation to connect wells Contract Contract Term (Years) Minimum Gathering Volume Commitment (MMcf/d) Minimum Processing Volume Commitment (MMcf/d) Minimum Volume Commitment Term (Years) Annual Rate Escalator Bridgeport gathering and processing contract 10 850 650 5 CPI East Johnson County gathering contract 10 125 - 5 CPI Northridge gathering and processing contract 10 40 40 5 CPI Cana gathering and processing contract 10 330 330 5 CPI Legacy Devon Midstream assets supported by fee-based contracts with minimum volume guarantees for five years 39
  • 40. North Texas Assets Positioned for Long-Term Performance Gathering  3,640 miles of pipeline  2,600 MMcf/d capacity Processing  4 plants 1,100 MMcf/d capacity  1 Stabilizer 5 MBbl/d  Truck and rail loading Fractionation  1 plant, 15 MBbl/d capacity Transportation  Gas Pipelines ̶ 260 miles of pipeline ̶ 1,300 MMcf/d capacity  NGL Pipelines ̶ 30 Miles ̶ 20 MBbl/d capacity 40
  • 41. 86% 12% 2% Devon Contracts Other Fee-Based Commodity-Based Processing Key Customers (most active operators in basin) North Texas Q2-Q4 2014 Forecasted Segment Cash Flow: ~ $304 MM * Contract Mix North Texas Assets: Solid Platform – Broad Reach Key Considerations  Premier position in Barnett shale  Largest gatherer and processor in the basin  Stable cash flow from firm contracts with significant volumes  Sizable acreage dedications with undrilled locations  Growth opportunities through consolidations & optimization 41* Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 42. North Texas Synergies: Operational Flexibility 42 Reduced O&M costs or increased revenues $20 MM annually Goal Reduced capital expendituresGoal  Currently implementing projects that save ~$4 MM annually  Interconnect systems reducing rental compression  Flow reconfiguration lowering system pressures / offsetting production declines  Increased blending of gas to reduce treating costs  Increased market share by providing producers more alternatives to receipt points, access markets, lower pressures  Identified capital savings opportunities of ~$15 MM  Reduced capital to connect new wells due to larger footprint  Reduced expansion capital by interconnecting systems to fully utilize installed capacity  Consolidate operations freeing up equipment for relocation (compressors / plants)
  • 43. North Texas Assets: Current Trends and Growth Strategy 5.1 5.2 5.6 5.7 5.2 2009 2010 2011 2012 2013 Average Annual Production (Bcf/d) * 0 10 20 30 40 50 60 70 80 90 Apr-11 Jul-11 Oct-11 Jan-12 Apr-12 Jul-12 Oct-12 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 Barnett Shale Current Trends  Reduced gas well drilling as result of low gas prices  Producers focused on optimizing base production Our Growth Strategy Short Term  Optimize combined systems  Enhance customer services  Execute identified expansion projects Long Term  Enhance customer services  Expand systems & customer base • Extend into new production areas • Support 3rd party and Devon activities & opportunities • Acquire and consolidate other assets 43 Barnett Shale Rig Count ** * Source: Power Shale Digest ** Source: Baker Hughes
  • 44. Oklahoma Assets: Solid Platform for Bolt-On Projects Cana  Gathering • 410 miles of pipeline • 530 MMcf/d capacity  Processing • 1 plant • 350 MMcf/d capacity Northridge  Gathering • 140 miles of pipeline • 75 MMcf/d capacity  Processing • 1 plant • 200 MMcf/d capacity $114 $126 Scoop Stack Arkoma Woodford 44
  • 45. Oklahoma Assets: Stable Cash Flows and Opportunities for 3rd Party Cash Flows Key Considerations  Large acreage commitments  Stable cash flow from firm contracts with significant volumes  Many undrilled locations on acreage dedications  Capacity to expand into several active plays Scoop Stack Arkoma Woodford Key Customers Oklahoma Q2-Q4 2014 Forecasted Segment Cash Flow: ~ $104 MM * 100% Fee-Based Contracts Contract Mix 45 * Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 46. Oklahoma Assets: Current Trends and Growth Strategy Current Trends  Reduced gas well drilling due to low gas prices  Producers focused on optimizing base production  Increased oil drilling generating associated gas, condensate and NGL production Our Growth Strategy Short Term  Maximize utilization of regional capacities with other midstream providers  Enhance customer services Long Term  Enhance customer services  Expand systems & customer base ̶ Support 3rd party and Devon activities & opportunities ̶ Extend into new production areas ̶ Develop new midstream infrastructure projects ̶ Acquire and consolidate other assets 46 100 125 150 175 200 225 Oklahoma Rig Count from 2012 to 2014 ** Oklahoma Total Devon Acreage in Oklahoma * * Source: DrillingInfo.com ** Source: Baker Hughes
  • 47. Permian Assets: A Platform in a Prolific Basin Gathering  65 miles of pipeline under construction  65 miles of fuel and gas lift pipeline under construction  200 MMcf/d capacity Processing  1 plant, 58 MMcf/d capacity (50% interest with Apache)  1 plant under construction, 60 MMcf/d capacity  Truck and rail loading Fractionation  1 plant, 15 MBbl/d capacity 47
  • 48. Permian Assets: Growing From Our Platform 48 Key Customers • Deadwood: • Bearkat: Two Producers Contract Mix Key Considerations • Focused on providing high pressure gathering and processing services for associated gas in extremely active drilling area • Currently constructing Bearkat facility and high pressure gathering system • Expanding from platform that started in 2012 with Deadwood facility and Mesquite fractionator Permian Q2-Q4 2014 Forecasted Segment Cash Flow: ~ $11 MM * 100% Fee-Based * Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 49. Permian Assets: Bearkat Project Processing and Gathering System Currently Under Construction  Builds on success of Deadwood joint venture with Apache, which was on-time, on-budget and is near full capacity  ~ 60 MMcf/d processing plant  ~65-mi., 12” gathering system with combined capacity of 200,000 Mscf/d  ~65-mi., 6” lean gas fuel line – providing producer fuel and gas lift  Supported by long-term, fee-based contracts with multiple producers  Completion expected in second half of 2014 49
  • 50. Permian Assets: Current Trends and Growth Strategy Permian Basin Current Trends  Increased oil drilling generating more associated gas, condensate and NGL production  Producers seek reduced wellhead pressures and reliable residue takeaway in order to maximize crude production Our Growth Strategy Short Term  Expand systems & customer base ̶ Provide capacity relief for constrained producers ̶ Support 3rd party and Devon activities & opportunities ̶ Extend into new production areas Long Term  Expand systems & customer base ̶ Support 3rd party and Devon activities & opportunities ̶ Extend into new production areas ̶ Develop new midstream infrastructure projects ̶ Acquire and consolidate other assets Cline Shal e Wolfcamp Shale Midland Basin Central Basin Platform + N/NW Shelf Delaware Basin Source: Wells – Rig Data Regions – Apache Glasscock County 300 350 400 450 500 550 600 Permian Rig Count from 2011 to 2014 ** 50 * Source: Apache ** Source: Baker Hughes Permian Basin Resource Plays*
  • 51. Natural Gas Assets: Potential Growth Projects from 2014-2017 51 North Texas Potential Projects Consolidation of Midstream Assets / Potential Acquisitions Compressor and Plant Consolidations Gathering Expansions Strategic Interconnects and Flow Reconfigurations to Lower Pressures Oklahoma Potential Projects Consolidation of Midstream Assets / Potential Acquisitions Interconnects w/ 3rd Party Pipes to Maximize Existing Capacities Various Gathering and Plant Expansions Permian Potential Projects Bearkat Processing Expansions Various Bearkat Gathering Expansions
  • 52. Mac Hummel, EVP, President of NGL and Crude Chris Tennant, VP of NGL Stan Golemon, SVP of Engineering Paul Weissgarber, SVP of Ohio River Valley Liquids Assets 52
  • 53. Liquids Business Unit Louisiana  NGL gathering and transportation  NGL fractionation  NGL storage  Crude handling  Natural Gas transportation  Natural Gas processing Ohio River Valley (ORV)  Crude/Condensate transportation  Crude/Condensate storage  Brine Disposal  Condensate Stabilization & Gas Compression 53 $126 $114 Liquids Business Unit Q2-Q4 2014 Forecasted Segment Cash Flow: ~ $133 MM * Gas 76% Liquids 24% * Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 54. Cajun-Sibon Expansion: Game Changer for EnLink in the Gulf Coast  258 miles of NGL pipeline from Mont Belvieu area to NGL fractionation assets in south Louisiana (195 miles new, 63 miles re-purposed)  140 MBbl/d south Louisiana fractionation expansion  Phase I completed fourth quarter 2013; Phase II projected completion in fourth quarter 2014  Expected run-rate adjusted EBITDA of Phase I and Phase II approximately $115 MM 54
  • 55. Louisiana Assets: Growing Gulf Coast Capabilities Crude Handling  2 terminals  ~18 MBbl/d capacity Natural Gas Transportation  2,000 miles of intra- state pipelines  2.0 Bcf/d of capacity Natural Gas Processing  6 plants  2.5 Bcf/d of capacity NGL Transportation  120 MBbl/d capacity post-Cajun-Sibon  789 miles of NGL pipeline in service  119 miles of NGL pipeline under construction NGL Fractionation  3 plants, 95 MBbl/d capacity  1 plant under construction, 100 MBbl/d capacity NGL Storage  3.2 MMBbl of underground NGL storage capacity 55
  • 56.  ~139 mile, 12-inch NGL pipeline from Mt. Belvieu to Eunice with NGL capacity of 70,000 Bbl/d  Expansion of Eunice NGL fractionator from 15,000 to 55,000 Bbl/d  Completed in Q4 2013 Cajun-Sibon Expansion – Phase I: Complete 56
  • 57.  Adding pumps to expand NGL pipeline capacity from 70,000 to 120,000 Bbl/d  100,000 Bbl/d fractionator at Plaquemine under construction  Converting Riverside fractionator to Butanes-plus facility  Extending Bayou Jack lateral by 32 miles to Plaquemine  Building ~57 miles of additional NGL pipelines  Expected run-rate adjusted EBITDA of Phase I and Phase II approximately $115 MM Cajun-Sibon Expansion – Phase 2: Expected completion in Q4 2014 57
  • 58. Louisiana NGL Assets: Linking North American Supply to Louisiana Demand Key Customers / Suppliers Contract Mix Key Considerations  Cajun-Sibon expansion provides access to North American NGL length flowing into Mont Belvieu and access to additional deal flow  Increased Louisiana NGL demand and insufficient Louisiana supply creates further expansion opportunities  NGL fractionation assets in south Louisiana provide flexibility and value Louisiana NGL Q2-Q4 2014 Forecasted Segment Cash Flow: ~$55 MM * 100% Fee-Based 58 * Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 59. Louisiana NGL Assets: Current Trends and Growth Strategy Current Trends  Louisiana industrial complex built to take advantage of offshore supply now reliant on non-Louisiana supplies  Infrastructure growing to connect NGL oversupply in Mont Belvieu area with NGL shortfall in Louisiana  Numerous industrial growth projects drive increased ethane demand due to attractive pricing and subsequent advantages garnered by U.S. petrochemical companies Our Growth Strategy Short Term  Fully utilize existing assets  Secure additional supply via spot/seasonal deals, transloading of raw make and other disadvantaged supplies  Assist customers in managing supply security and delivery flexibility Long Term  Optimize supply, capacity and logistics across basins and hubs  Expand Cajun-Sibon platform through bolt-on growth projects or acquisitions  Rationalize EnLink and Devon NGL supply positions 0 100 200 300 400 500 2013 2018 Supply Demand 0 10 20 30 40 50 60 Global Ethylene Cash Costs ** (Cents per Lb of Ethylene) Mid-East Ethane Canadian Ethane U.S. Ethane Mid-East Propane W. Euro Naphtha SE Asia Naphtha NE Asia Naphtha 59 Louisiana Ethane Supply/Demand * (MBbl/d) * Source: Hodson Report, February 2013 ** Source: En*Vantage
  • 60. Louisiana Crude Assets: Terminals at Eunice and Riverside Facilities 60 Key CustomersKey Considerations  Crude assets at Eunice and Riverside with attractive rail, truck and barge capabilities  Well positioned to service local demand and local supply as it develops  Well positioned via rail service for Canadian and other regional supplies  Riverside terminal provides $10 MM of annual Adjusted EBITDA under firm contract Nearburg Producing Louisiana Crude Q2-Q4 2014 Forecasted Segment Cash Flow: ~$8 MM * Contract Mix 100% Fee-Based * Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 61. Louisiana Crude Assets: Current Trends and Growth Strategy Current Trends  Dramatic growth in U.S. crude production  Significant crude supplies moving by truck and rail with producers increasingly involved with logistics  Condensate supply growing with more competitive pricing  Growing discussions about exports Our Growth Strategy Short Term • Increase asset utilization with pipeline supplies, Riverside rail-to-barge loading and Eunice rail-to-truck trans-loading • Purchase crude at the lease and utilize assets to capture blending uplifts and regional arbitrage opportunities Long Term • Expand Riverside terminal to provide unit train service for 20 – 40 MBbl/d • Pursue crude/condensate opportunities with Devon • Acquire assets complementing existing facilities and growing footprint 32% 19% U.S. Crude Production * 61* Source: EIA ** Source: Association of American Railroads Rail Carloads of Crude Petroleum on US Class I Railroads from 2003-2015**
  • 62. Louisiana Natural Gas Assets: Pipeline and Processing Plant Flexibility Key CustomersKey Considerations • Largest intrastate gas pipeline system in Louisiana - north Louisiana assets supported by firm contracts averaging remaining term of ~4.0 years • Transportation and processing assets well positioned to support new Louisiana and Gulf of Mexico supplies • Mississippi River market area heavily industrialized and expanding Pipeline Customers Louisiana Gas Q2-Q4 2014 Forecasted Segment Cash Flow: ~$43 MM * 74% 26% Fee-Based Commodity-Based Processing Contract Mix 62 Processing Customers * Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 63. Louisiana Natural Gas Assets: Current Trends and Growth Strategy Current Trends  Tuscaloosa Marine Shale, Austin Chalk and Deep Miocene/Wilcox targets continue to attract producer interest and investment  Producers refocusing efforts on liquids-richer Cotton Valley/Bossier targets versus Haynesville  Louisiana gas demand growing with petrochemical, industrial and LNG expansions Our Growth Strategy Short-Term Strategy  Maximize existing capacity  Optimize supply via new connections  Maximize processing margins and opportunities  Expand market connectivity to service petrochemical, industrial and LNG demand along the Mississippi River Long-Term Strategy  Pursue strategic acquisitions  Consolidate inefficient facilities and utilize existing assets in highest value use  Expand position as premier Louisiana gas franchise Capital Spending for Announced Louisiana Natural Gas Driven Manufacturing ** Louisiana Gas Demand (Bcf/d) 2010 – 2025 * 63* Source: ICF International ** Source: LSU Center for Energy Studies
  • 64. Ohio River Valley Assets: Established History of Service Crude/Condensate Transportation  200 miles of crude pipeline, 17 MBbl/d capacity  2,500 miles of unused right-of-way  Truck fleet capacity of 25 MBbl/d  Barge terminal on Ohio River  Rail terminal on Ohio Central Railroad Crude/Condensate Storage  ~600 MBbl of above ground storage Brine disposal wells  8 total wells – 6 owned, 2 jointly-owned 64
  • 65. 80% 20% Fee-Based Crude/Condensate Fee-Based Brine Ohio River Valley Assets: Well Positioned in the Utica and Western Marcellus Key CustomersKey Considerations  Pipeline and terminal assets strategically located in Utica’s condensate-rich window where stabilization requirements are significant  Truck fleet provides access to both the Utica and the Western Marcellus in Pennsylvania and West Virginia  Establishing “rolling pipeline” via truck fleet until volumes warrant laying new pipelines  Brine disposal capacity increasingly stressed ORV Q2-Q4 2014 Forecasted Segment Cash Flow:~$28 MM * Contract Mix 65 * Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 66. ORV Assets: Current Trends and Growth Strategy Current Trends  Producers are delineating their acreage and high-grading drilling locations  Condensate supplies from the Utica and Western Marcellus are growing  Out-of-region condensate markets will be needed  Midstream imperatives are high flow assurance and reliable market outlets Short Term Growth Strategy  Establish “rolling pipeline” via truck fleet to capture “first barrels”  Optimize our existing assets and businesses in legacy crude and brine disposal assets Long Term Growth Strategy  Complete condensate pipeline and expansion of condensate stabilization and storage  Develop premium condensate markets including potentially building and operating a condensate refinery  Pursue additional midstream opportunities including gas gathering and processing and NGL movements 66 15 20 25 30 35 40 45 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 Jan-14 Feb-14 Mar-14 Ohio Pennsylvania West Virginia * Sources: Ohio Department of National Resources, Pennsylvania Department of Environmental Protection, West Virginia Department of Natural Resources ORV Rig Count * ORV Drilling Permits Issued * 0 100 200 300 400 500 600 700 Q3 '12 Q4 '12 Q1 '13 Q2 '13 Q3 '13 Q4 '13 Q1 '14 Ohio Pennsylvania West Virginia
  • 67. Louisiana Potential Projects Consolidation of Midstream Assets / Potential Acquisitions LPG Export Facility Mixed Heavy NGL Pipeline Terminal Repurposing NGL Batching Pipeline Market-Area Pipeline ORV Potential Projects Consolidation of Midstream Assets / Potential Acquisitions Condensate Refinery Condensate Pipeline 67 Liquids Assets: Potential Growth Projects from 2014-2017
  • 68. Non-Operated Investments Brad Iles, SVP of Business Development 68
  • 69. Howard Energy Investment: Strategic South Texas Asset Footprint Key Customers Ownership Structure 31% 59% 10% EnLink Midstream Alinda Capital Partners HEP Management Key Considerations  Howard Energy Partners (“HEP”) is a high growth midstream company with a strategically located asset base in South Texas  Franchise position in western Eagle Ford with access to multiple producing zones (Eagle Ford, Olmos, Escondido, Pearsall and Buda)  Diverse footprint including rich & dry gas gathering, processing, liquids terminalling and stabilization assets  ~70% of cash flow underwritten by firm contracts with minimum volume commitments 69 HEP Q2-Q4 2014 Forecasted Distribution Income:~$20 MM
  • 70. E2 Investment: Innovative Solution to Grow ORV Condensate Business Customer 70 E2 Q2-Q4 Cash Flow Post-Dropdown:~$9 MM Key Considerations  E2 is 93% owned by ENLC and 7% owned by E2 management  E2 is highly skilled management team focused on building compression and stabilization assets in the Utica and Marcellus region  100% fee-based contracts with minimum volume commitments to ORV growth strategies  Approximately $80 million invested to date through EnLink Midstream, LLC with dropdown expected mid-year 2014 E2 Compression & Condensate Stabilization  Capacity of 320 MMcf/d and 16,000 Bbl/d  Two facilities completed, one under construction
  • 71. Gulf Coast Fractionator Investment: Serving Devon in Mont Belvieu 71 38.75% 22.50% 38.75% Key Considerations  EnLink owns a contractual right to the economics of Devon’s interest in the Gulf Coast Fractionator (GCF)  GCF is a partnership between Devon, Targa and Phillips 66 with Phillips 66 serving as the operator  Located at Mont Belvieu, Texas, GCF has capacity of ~ 120–145 MBbl/d depending on composition  GCF provides fractionation services for a large percentage of Devon’s equity NGLs Targa Resources Devon Phillips 66 GCF Estimated Q2-Q4 Cash Flow:~$9 MM
  • 72. Financial Outlook Michael Garberding, EVP & Chief Financial Officer 72
  • 73. Sustainable Growth Substantial Scale & Scope Diverse, Fee-Based Cash Flow Strong B/S Credit Profile 73 • Investment grade balance sheet at ENLK (BBB, Baa3) • Debt/EBITDA of ~3.5x • ~$1.0 billion in liquidity • ~ 95% fee-based margin • Projects focused on crude/NGL services and rich gas processing • Balanced cash flow (Devon ~50%) • Total consolidated enterprise value of ~$14 billion • Geographically diverse assets with presence in major US shale plays • Stable base cash flow supported by long-term contracts • Organic growth opportunities through Devon’s upstream portfolio • Potential additional cash flow from dropdowns: ~$375 million Louisiana ORV Long Term Vision: EnLink’s Key Financial Attributes
  • 74. Long Term Vision: Strong Balance Sheet  ENLK has investment grade (BBB/Baa3) credit ratings ̶ Leverage target of ≤ 3.5x EBITDA provides access to relatively inexpensive debt capital  On March 12th, EnLink priced $1.2 billion in senior notes with a weighted-average yield to maturity of 4.20%:  Significant liquidity/financial flexibility with $1 Billion revolving credit facility at MLP and $250 MM revolving credit facility at GP  EnLink’s strong credit position gives it significant capacity to pursue organic growth or acquisitions 74 EnLink has one of the strongest balance sheets in the industry 2.700% Senior Notes Due 2019 4.400% Senior Notes Due 2024 5.600% Senior Notes Due 2044 Principal Amount $400,000,000 $450,000,000 $350,000,000 Maturity Date 1-Apr-19 1-Apr-24 1-Apr-44 Spread to Treasury +115 bps +170 bps +195 bps Yield to Maturity 2.732% 4.421% 5.605%
  • 75. Strong Balance Sheet: Execution of Financial Synergies EnLink financing activity has positioned the company to realize financial synergies of over $35 MM annually compared to Crosstex standalone  Refinancing $725 MM of 8.875% bonds due 2018 ̶ Including call / tender premium, total cost to retire of ~$760 MM ̶ Weighted-average interest rate on new bonds of 4.2% results in annual interest savings of ~$32 MM  Equity claw redemption of $53.5 MM of 7.125% bonds due 2022 ̶ Including redemption premium, cost to retire of ~$57 MM ̶ Annual interest savings of ~$1.4MM  Reduction in letters of credit of ~$44 MM ̶ Annual interest savings of ~$1.3 MM  Reduction in revolving credit facility interest and fees ̶ Reduction in undrawn commitment fee from 0.5% to 0.175% ̶ Reduction in drawn spread from +300bps to +125bps at current EnLink ratings 75 At the time the merger was announced, EnLink guided the market to expect financial synergies of $25 million
  • 76. Long Term Vision: Stable and Diversified Cash Flows 76 Each of EnLink Midstream’s segments benefits from the stability provided by long-term, fee-based contracts Segment / Key Contract % of Q4 2014 Segment Cash Flow Texas New Devon Bridgeport Contract - 10 years with 5 year MVC 85% New Devon East Johnson County Contract - 10 years with 5 year MVC Existing FT Transmission & Gathering - Volume Commitments with remaining terms of 2-10 years Apache Deadwood Plant - Dedicated interest with 8.5 years remaining on 10 year term Bearkat Plant - Volume Commitment with 10 year term from initial flow Oklahoma New Devon Cana Contract - 10 years with 5 year MVC 100% New Devon Northridge Contract - 10 years with 5 year MVC Louisiana North LIG Firm Transport - Reservation fee with avg remaining life of 4 years 70% Firm Treating & Processing - Remaining term minimum 2 years Cajun-Sibon Phases I & II - 5 & 10 year agreements for supply and sale of key products ORV E2 Compression / Stabilization Contract - 7 years ~30% % of Total Segment Cash Flow in Q4 2014 ~80% Note: Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income.
  • 77. Long Term Vision: Sustainable Growth 77 Distribution growth targets are high single digits for MLP and 20% plus for GP 2014 2015 2016 2017 Estimated Capital Cost: $80 MM Estimated Cash Flow: ~$12 MM Estimated Capital Cost: $1.0 B Estimated Cash Flow: ~$150 MM Acquisition Cost: $2.4 B Estimated Cash Flow: ~$200 MM Estimated Capital Cost: $70 MM Estimated Cash Flow: ~$12 MM Other Potential Devon Dropdowns E2 Legacy Devon Midstream Assets Access Pipeline Victoria Express Pipeline Cautionary Note: The information on this slide is for illustrative purposes only. No agreements or understandings exist regarding the terms of these potential dropdowns, and Devon is not obligated to sell or contribute any of these assets to EnLink. The completion of any future dropdown will be subject to a number of conditions. The capital cost and cash flow information on this slide is based on management’s current estimates and current market information and is subject to change.
  • 78. 2014 EBITDA & Volumes Forecasts Q2-Q4 2014 Combined Annualized EBITDA: ~ $675 MM * 57% 19% 19% 5% Texas Louisiana Oklahoma ORV Midstream Service: Q2 - Q4 2014 Forecasted Volumes Texas Gathering and Transportation (MMBtu/d) 2,968,000 Processing (MMBtu/d) 1,022,000 Louisiana Gathering and Transportation (MMBtu/d) 499,000 Processing (MMBtu/d) 585,000 NGL Fractionation (Gals/d) 3,570,000 Oklahoma Gathering and Transportation (MMBtu/d) 389,000 Processing (MMBtu/d) 391,000 ORV Crude/Condensate Handling (Bbls/d) 1 28,000 Brine Disposal (Bbls/d) 7,000 1. Includes crude/condensate handling by both the ORV and Louisiana segments. * Segment cash flow is a non-GAAP financial measure and is explained in greater detail on page 3. See Appendix for reconciliation to Operating Income. 78
  • 79. Key Performance Drivers Short Term Performance Drivers  Timing and execution of Cajun Sibon II and Bearkat Projects  Drilling activity in Barnett and Oklahoma  Remediation of Bayou Corne Sinkhole  Timing/amount of operational synergies  Timing of Utica condensate production and ORV execution Long Term Performance Drivers  Potential additional cash flow from dropdowns: $375 million  Stable cash flows from long-term Devon contracts  Organic development in west Texas and south Louisiana  Organic development with Devon 79
  • 80. 2014 Consolidated Capital Expenditures 80 Potential long term capital spending of $1.0 billion - $2.0 billion per year with drop downs $200 MM $194 MM Cajun-Sibon Bearkat Other $50 MM Legacy DVN $46 MM Growth Capex * Q2-Q4 ‘14 Combined: ~$490 MM $43 MM $12 MM $7 MM Texas Oklahoma ORV $2 MM Louisiana Maintenance Capex * Q2-Q4 ‘14 Combined: ~$65 MM * Growth capital expenditures and maintenance capital expenditures are non-GAAP financial measure and are explained in greater detail on page 3.
  • 81. ENLC Tax  ENLC has three principal sources of cash flow, each with different level of exposure to federal income tax ̶ GP Distributions/IDRs: ENLC receives an allocation of taxable income in the amount of its IDR distributions such that they are fully taxable ̶ LP Distributions: Distributions from ENLK to ENLC receive a lower tax shield (about 50%) than public unit holders ̶ Income from EnLink Midstream Holdings: Taxable income is estimated to be at ~70% of cash flow in 2014  ENLC also receives deductions for its direct interest expense, G&A Costs, etc.  Results in an effective tax rate of ~20% in 2014 before the application of net operating loses (NOLs) ̶ Includes one-time benefit from transaction related expenses  As dropdowns are executed, the composition of ENLC’s cash flow streams, and therefore its effective tax rate will change ̶ Degree of tax shield on LP distribution may also change over time  ENLC also has available $146 MM in federal NOL carry forwards ̶ After NOL usage, ENLC currently estimates minimal 2014 cash taxes 81
  • 82. Closing Remarks Barry Davis, President & CEO 82
  • 83. Key Takeaways 83 The right team in place Strategically located and complementary assets Stability of cash flows Strong sponsorship support from Devon Continued focus on organic growth projects
  • 84. Appendix 84
  • 85. Reconciliation: Segment Cash Flow to Operating Income 85 (Amounts in MM) Q2-Q4 Forecasted ‪ Total business unit segment cash flow $555 ‪ Shared services (26) ‪ General and administrative expenses (53) ‪ Other * (14) ‪ Depreciation, amortization and impairment (215) Operating Income $247 * Other includes stock based compensation and loss on debt extinguishment
  • 86. Reconciliation: Net Income to Consolidated Adjusted EBITDA 86 (Amounts in MM) Q2-Q4 Annualized ‪ Net Income $287 ‪ Interest expense 45 ‪ Depreciation, amortization and impairment 287 ‪ Net distribution from equity investments 40 ‪ Other * 16 Consolidated Adjusted EBITDA $675 * Other includes taxes, stock based compensation and other non-cash items