Growth Outlook Liquids Pipelines organic growth program underway • New infrastructure, expansion and market access • Highly certain returns and long term cash flows Execute on growth program • Deliver projects on-time and on-budget • Financial execution: translate organic growth into financial success • Visible distribution growth • Strengthen valuation Position the Partnership as a drop-down vehicle for Enbridge Inc. • Substantial and attractive inventory of drop-down assets 10
Distribution Growth Target Organic growth platform supports distribution growth 2% - 5% Annual Growth Target - 4.2% 3.6% 2.1% 2.7% 3.8% - 2007 2008 2009 2010 2011 2012 2013 2017e 11
Long-Term ENB Liquids Drop-Down Potential: $10 Billion + Distributable Cash Examples: Capital Cost/ Pipeline System Upsize Option Book Value* Eastern Access $0.4 (2016/2017) ~ $1.5 Mainline Expansion $0.4 ( 2016/2017 ) ~ $1.4 Alberta Clipper - ~ $0.8 Line 3 Replacement** $0.4 (2018) ~ $0.9 Flanagan South - ~ $2.8 Seaway/Seaway Twin - ~ $2.4 ~ $10B 2017e ($ Billions) Substantial drop-down opportunities from parent supports long-term growth outlook * Estimated capital cost or net book value of assets held by Enbridge Inc. ** Line 3 Replacement Joint Funding Agreement to be finalized by a Special Committee of the independent Board of Directors., including an option to upsize EEP ownership by 15% one year after the in-service date. 12
Operational Reliability & Project Execution Operational Project Reliability Execution Project Development Third Party Damage Incident Response Avoidance and Capacity Detection Supply Chain Management Employee and Leak Detection Contractor Capability and Major Occupational Safety Control Systems Life Cycle Gating Control Projects Construction Public Safety and Industry Integrity Experience Environmental Leadership Management Protection Regulatory & Permitting Organizational commitment to being “best in class” Proven track record: on-time & on-budget 13
Key Takeaways • Strategic position supported by strong business fundamentals • Secured Liquids projects collectively further transform the Partnership to even lower risk business model • Coverage strengthens as projects enter service • Distribution growth: targeting 2% to 5% annual growth • Position the Partnership as a drop-down vehicle for Enbridge Inc. • Attractive long-term growth outlook • Maintaining investment grade credit rating is a priority Safety and operational reliability are cornerstones that underpin our business and growth outlook 14
Corporate Structure Enbridge Inc. owns Enbridge Inc. ~21% of EEP (NYSE: ENB) 11.7% of listed shares 100% voting interest (Baa1 / A-) Enbridge Energy Management, L.L.C. 2% GP interest (NYSE: EEQ) 16.3% LP interest (indirect) 88.3% of listed shares Public Unitholders 19.5% LP Public interest (I-units) 62.2% LP Unitholders Enbridge Energy Partners, L.P. interest (NYSE: EEP) (Baa2 / BBB) 2% GP interest Public 52% LP interest Unitholders 46% LP interest Midcoast Energy Partners, L.P. (NYSE: MEP) 61% LP interest 100% interest (indirect) 39% LP interest Midcoast Operating, L.P. “Midcoast Operating” 100% ownership interest 35% ownership interest Texas Express NGL System Operating Subsidiaries Joint Venture Corporate structure as of March 21, 2014 15
LIQUIDS PIPELINES Guy Jarvis, President, Liquids Pipelines, Enbridge Inc.
Key Messages • Strong North American crude oil supply fundamentals • Market access program bolsters competitive position • Lakehead system ideally positioned • Enbridge will continue to be premier liquids pipeline system to provide access to multiple premium markets • Transforming secured growth projects into operational and financial success Safety and operational reliability are cornerstones that underpin our business and growth outlook 2
North American Crude Oil Supply Growth (2013 – 2025) + 7 MMbpd by 2025 MMbpd 4.0 Cardium, Viking, Duvernay 3.5 Niobrara 3.0 Other 2.5 Permian Basin 2.0 Oil Sands Eagle Ford 1.5 1.0 Bakken 0.5 0.0 Heavy Light Sources: Enbridge Internal Forecast and External Forecasts 3
US Refining Crude Coverage North American Production Displaces Waterborne Imports MMb/d 18.0 16.0 14.0 12.0 10.0 8.0 6.0 4.0 2.0 0.0 2013F 2015 2020 2025 US Production Waterborne Imports Imports from Canada Sources: Enbridge Internal Forecast 4
North American Crude Oil Price Fundamentals Significant Infrastructure Investment Opportunities Light Differentials Asia Brent – WTI $6 $112 LLS – WTI Alberta Light $3 $94 $102 Asia – WTI $12 WCS $79 WTI – Bakken $6 Bakken $94 WTI - Alberta $6 Light $106 Brent WTI North American Supply Heavy Differentials $100 North American Demand Maya – WCS $10 Light Crude Transportation Bottlenecks LLS Maya Asia – WCS $23 Heavy Crude $103 Volatile Price Differentials $89 March 20, 2014 prices (in US$/bbl) 5
WCSB Supply Forecast vs. Pipeline Takeaway Capacity* MMb/d 9.0 Keystone XL Supply Forecast ENB Northern Gateway 8.0 TransMountain Expansion Energy East 7.0 6.0 5.0 4.0 ENB 3.0 2.0 OTHER 1.0 0.0 2013 Enbridge Forecast 2013 Enbridge Upside Forecast Optimal Pipeline Capacity Sources: Enbridge Internal Forecast *Includes Bakken entering ENB Mainline ex-Superior 6
Bakken Crude Oil Supply vs. Pipeline Takeaway Capacity MMb/d 2.5 2.0 Range of External 1.5 Supply Forecasts 1.0 Enbridge Sandpiper* Plains Bakken North Baker Take-away (Platte) 0.5 Enbridge Berthold Rail ND Enbridge Bakken Pipeline Enbridge North Dakota system Tesoro Mandan Refinery 0.0 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 * Sandpiper construction to be funded 37.5% by Marathon Petroleum Corp; Marathon to assume ~27% equity participation in expanded EEP North Dakota System after Sandpiper in-service. 7
Strategic Position Competitive Advantages • Refiners Norman Wells – Access to multiple crude streams • Producers WCSB Zama – Access to multiple premium markets Fort McMurray • Flexible system Edmonton Hardisty • Size and scale unmatched St. John Regina Cromer – Will expand to ~2.85 MMb/d in 2017 Seattle Clearbrook Montreal Ottawa Portland Superior Positioned for Long-Term Growth Toronto BAKKEN Buffalo Sarnia Casper • Toledo Direct connection to growing supply basins (Heavy Flanagan Philadelphia Chicago Salt Lake City & Light) Patoka Wood ENB and EEP Strategically Aligned Cushing River EEP Contract Storage St. James EEP Liquids Pipelines Houston ENB Liquids Pipelines 8
Providing New Market Access Opening New Markets for up to 1.7 million barrels per day + ~1.0 MMbpd of Heavy and + ~0.7 MMbpd of Light Norman Wells Eastern Access Light Oil Market Zama Fort McMurray +250 kbpd Light Access +50 kbpd Heavy Edmonton Hardisty Western USGC Regina +50 Access Cromer kbpd St. John Seattle Light Clearbrook Superior Montreal Portland Buffalo Organic Growth Projects: +50 +250 Nanticoke Sarnia kbpd kbpd Casper Toledo Heavy Light Commercially secured Flanagan Chicago Salt Lake City +80 Patoka kbpd Low risk framework Heavy Cushing +300 +600 Long-term contracts kbpd kbpd Light Heavy St. James Houston 9
Market Access – Eastern Access Linking North American crude supply growth to eastern refining centers Hardisty Montreal 1 5 Superior 4 Westover Sarnia 1. Line 5 Expansion +50 Mb/d (In-Service) 1 Chicago 2. Spearhead North Expansion +105 Mb/d 2 3 6 Toledo (Line 62) (In-Service) Flanagan 2 3. Line 6B Replacement +260 Mb/d (2014) 3 4 4. Line 9A Reversal +240 Mb/d (In-Service) Patoka 5. 5 Line 9B Reversal +240 Mb/d (2014) EEP/ENB Joint Funded 6. Toledo Pipeline Twin +80 Mb/d (In-Service) 6 ENB Funded Cushing 10
Market Access – Light Oil Market Access (LOMA) Matching light oil supply growth to key markets Hardisty Cromer Gretna Montreal Clearbrook Superior 1 5 Westover EEP/MPC funded Stockbridge Sarnia 2 EEP/ENB joint funded 4 ENB funded Toledo Sandpiper Pipeline +225/+375 Mb/d (2016) 3 1 Flanagan Chicago Line 61 Expansion + 640 Mb/d (2016) 2 6 Line 62 Twin +570 Mb/d (2015) 3 Patoka 4 Line 6B Expansion +70 Mb/d (2016) Line 9 Expansion +60 Mb/d (2014) 5 Southern Access Extension +300 Mb/d 6 (2015) 11
Market Access – US Gulf Coast Linking North American crude supply growth to USGC refining centers 4 5 EEP/ENB Funded ENB Funded Refining center Chicago/ Flanagan 2 Seaway Pipeline 400 Mb/d (In Service) 1 Flanagan South Pipeline +585 Mb/d Cushing 2 (2014) Western USGC Refining 3 1 Seaway Pipeline Twin & Lateral +450 3 Processing Capability (~4,400 Mb/d) Mb/d (2014) 4 Line 67 Expansion +350 Mb/d by 2015 (1) Heavy Light 43% 57% 5 Houston Line 61 Expansion +160 Mb/d by 2014 Port Arthur 12 Source: EIA and Enbridge’s internal estimates (1) Phase 1 of Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions. 12
Bakken Infrastructure EEP pipeline takeaway will reach 580 kbpd with next phase of expansion Enbridge Mainline Saskatchewan System (ENF) North Dakota System (EEP) • 210 Mb/d Bakken Pipeline (EEP, ENF) Manitoba • 145 Mb/d Bakken Access Program (EEP) 100 Mb/d Weyburn Berthold Rail (EEP) • 80 Mb/d Cromer Steelman Sandpiper (EEP, MPC)* • 225/375 Mb/d ( Early 2016 ISD ) Lignite Tioga Stanley Gretna Minot Berthold Clearbrook to Superior *Marathon Petroleum Corp. will fund 37.5% of Project Sandpiper cost and assume a ~27% equity 13 interest in the EEP North Dakota system, once the project enters service.
Bakken Expansion – Sandpiper Pipeline Hardisty Regina Gretna Montreal Clearbrook Superior Sandpiper ($2.6 B) Westover • Scope: 610 mile, 24”/30” pipeline Sarnia • Capacity: ~ 225 kbpd/375 kbpd • Target in-service: Early 2016 Toledo Chicago • Marathon Funding: 37.5% of construction for ~27% equity Patoka interest in EEP ND system Low risk framework (ship-or-pay/COS) Anchor Shipper secured Petition for Declaratory Order filed with FERC Cushing 14
Line 3 Replacement • Line 3: – Part of Enbridge mainline system – Replace all remaining segments from Hardisty to Superior with latest available high strength steel and coating technology • EEP Capital Investment: – border to Superior ~ $2.6 billion capital – to be joint funded with ENB • Expected Completion: – 2nd Half of 2017 • 30 year Cost-of-Service • Shipper Support (CAPP/RSG) 15
Growth and Project Integration Market Access Programs Bolster Lakehead System Utilization 2013 Fort McMurray • Bakken Pipeline Expansion+ Berthold Rail - EEP • Line 5 Expansion (+50 kbpd) - EEP • Line 62 Expansion (+105 kbpd) - EEP • Edmonton Line 9A Reversal (+50 kbpd) - ENB Hardisty • Toledo Pipeline Partial Twin (+80 kbpd) - ENB • Kerrobert Seaway Pipeline Expansion (+400 kbpd) - ENB Regina +300 2014 Cromer kpbd Gretna • Line 6B Replacement (+260 kbpd) - EEP Montreal • Line 67 (+120 kbpd) (1) - EEP Superior • Line 61 (+160 kbpd) - EEP Westover • Line 9B Reversal + Expansion (+300 kbpd) - ENB • Flanagan South Pipeline (+585 kbpd) - ENB Buffalo • Seaway Twin + Lateral (+450 kbpd) - ENB Sarnia 2015 Toledo Chicago/ +80 Flanagan • Line 67 (+230 kbpd) – ENB / EEP kbpd • Line 61 (+640 kbpd) - EEP +300 • Chicago Area Connectivity (+570 kbpd) – EEP Patoka kbpd • Southern Access Extension (+300 kbpd) - ENB Cushing • Edmonton to Hardisty (+570 kbpd) - ENB 2016 • Sandpiper Pipeline (+225/+375 kbpd) – EEP +440 • Line 6B Expansion (+70kbpd) - EEP +600 Port Arthur kbpd kbpd 2017 Houston • Line 3 Replacement – ENB/ EEP 16 (1) Phase 1 of Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions.
Safety and Operational Reliability Risk Management • Risk Policy, Risk Framework, Risk Culture Survey + Training Inline inspection (ILI) • Significant dig program 3,400 pipe joints examined followed with non-destructive testing • Research and Development in tool enhancements - Medical imaging technology On-line sensors • Pressures/cycling, pipe movement, external & internal corrosion, vibration Surveys • Pipe depth, river crossing and geotechnical conditions, corrosion control, 3rd party activity Incident Response • Focused Emergency response tactical plans Health & Safety • Process safety management implementation 17
Key Takeaways • Strong North American crude oil supply fundamentals • Market access program bolsters competitive position • Lakehead system ideally positioned • Enbridge will continue to be premier liquids pipeline system to provide access to multiple premium markets • Transforming secured growth projects into operational and financial success Safety and operational reliability are cornerstones that underpin our business and growth outlook 18
MAJOR PROJECTS Byron Neiles, Senior VP , Major Projects, Enbridge Inc.
Key Messages • $31B portfolio represented by 35 projects • $11B EEP portfolio represented by 11 projects • Scalable workforce, strong supply chain relationships • Effective permitting approach • Unwavering commitment to safety • Proven track record 2
Major Projects – A Core Competency President & CEO Al Monaco Senior VP Major Projects Byron Neiles VP CDN Liquids VP Offshore & VP U.S. Liquids VP U.S. Liquids VP CDN Oil VP EPC and & Green Gas Execution Execution Execution Sands Execution Project Services Execution New for 2014 Stats • Line 3 Replacement • Staff – 1,600+ • Beckville Plant • Field – 10,000+ • Portfolio – $31B 3
Project Development Expertise • Well known corridors • Comprehensive historic project and market cost data • Reliable cost estimating and schedules • Standardized designs • Team of technical experts 4
Secured Supply Chain & Resources Enbridge Pipe vs. Market Pricing • Multi-year frame agreements US$ / Short Ton Pipe Enbridge Market • Growing & diversifying supply chains Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 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 • Scalable workforce • Continuous organizational reviews 5
Regulatory and Permitting Effectiveness • Received 100% of permits applied for since 2010 • Proactive stakeholder engagement • Thorough and transparent land and environmental reviews • Emphasis on integrity & safety 6
Path to Zero Safety Culture MP Historical Safety Performance • 10,000+ temporary workforce MP TRIF Frequency 3 Year Rolling Avg 3.0 2.5 50% 2.0 • Record field hours 1.5 1.0 1.50 1.28 1.04 0.5 1.00 • Significant focus on leading 0.84 0.0 indicators 2009 2010 2011 2012 2013 • Prevention, training and surveillance • Aligning contractor and industry safety performance 7
Proven Execution Track Record • Disciplined control: cost, schedule and quality • Rigorous risk identification and mitigation • Extensive governance and reporting • Repeatable execution • Experienced teams 8
Eastern Access Phases 1 & 2 The Project: • Line 6B 210 mile pipe replacement • New pump stations, tankage and terminal upgrades • Line 62 Horsepower Expansion Cost: • $2.1 Billion* In-service date: • Range of ISDs 2013 – 2014 Status: • 160 miles of Line 6B replacement is on target to begin line fill in April • ROW and permitting for the remaining 50 mile replacement secured, construction to begin this spring for Q3 2014 in service date * Jointly funded 25% EEP / 75% ENB 9
U.S. Mainline Expansion The Project: • Ph. 1: Line 67 450 kbpd to 570 kbpd Line 61 450 kbpd to 560 kbpd • Ph. 2: Line 61 560 kbpd to 1,200 kbpd • Ph. 3: Line 67 570 kbpd to 800 kbpd Cost: • U.S. Portion: $1.9 Billion* In-service date: Status: • • Leveraged existing footprint Range of ISDs 2014 - 2016 • Standard station design • Secured construction permits; construction underway * Jointly funded 25% EEP / 75% ENB 10
Sandpiper The Project: In-service date: • 2016 • Capacity 375 kbpd for 238 miles, 30” pipe • Capacity 225 kbpd for 317 miles, 24” pipe Status: • Capacity 250 kbpd for 57 miles, 24” pipe • Right-of-Way acquisition ahead of plan and currently at 50% • 4 pump stations & 7 tanks • Major Federal Permit Applications Cost: completed and submitted to the US • $2.6 Billion* Army Corps of Engineers * Jointly funded 62.5% EEP / 37.5% Williston Basin Pipe Line LLC (a subsidiary of Marathon Petroleum Company) 11
Line 3 Replacement The Project: • Replace 1,031 miles of 34” pipeline with 36” pipeline Cost: • U.S. Portion: $2.6 Billion* In-service date: • 2017 Status: • Reassembled successful Alberta Clipper project team • Securing supply chain • Known corridor with established relationships * Project to be jointly funded by ENB and EEP at participation levels to be finalized and approved by a Special Committee of the independent Board of Directors. 12
Beckville Plant The Project: • 150 MMcf/d Cryogenic Natural Gas Processing Plant near Beckville, Texas Cost: • $0.1 Billion* In-service date: • 2015 Status: • Key components procured early • Construction contract awarded • Construction permit authorized by Texas Commission on Environmental Quality * Project is funded by EEP and MEP based on their proportionate ownership in Midcoast Operating, which is currently 61% and 39%, respectively 13
Key Takeaways • Executing with confidence • Dedicated, scalable construction capability • Rigorous controls and governance • Disciplined processes • Majority of projects tracking on time and budget • Proven track record 14
STRATEGIC OVERVIEW - MEP Greg Harper, President, Gas Pipelines & Processing, Enbridge Inc. Principal Executive Officer, Midcoast Energy Partners, L.P .
Key Messages Execute growth strategy • First drop-down post-IPO expected mid-2014 • 100% debt-funded • Deliver target distribution growth rate • Secure new growth opportunities Strengthen underlying business performance • Deliver on actionable opportunities – optimization, enhanced market access, and optionality • Manage and pursue opportunities to reduce volume and commodity price sensitivity Vision : Become leading natural gas and NGL midstream infrastructure developer, operator and service provider • Continue to provide ‘best in class’ gathering, processing & transportation solutions to customers Safety and operational reliability are cornerstones that underpin our business and growth outlook 2
Corporate Structure Enbridge Inc. owns Enbridge Inc. ~21% of EEP (NYSE: ENB) (Baa1 / A-) 2% GP interest 16.3% LP interest (indirect) Enbridge Energy Partners, L.P. (NYSE: EEP) (Baa2 / BBB) 2% GP interest Public 52% LP interest Unitholders 46% LP interest Midcoast Energy Partners, L.P. (NYSE: MEP) 61% LP interest 100% interest (indirect) 39% LP interest Midcoast Operating, L.P. “Midcoast Operating” 100% ownership interest 35% ownership interest Texas Express NGL System Operating Subsidiaries Joint Venture Corporate structure as of March 21, 2014 3
Attractive Investment Proposition Peer Group Investment Highlights • 39% interest in Midcoast 10% Operating 9% • Remaining interest available for MEP: 6.1% drop-down ~$3 billion (2) 8% • Valuation to improve as we 7% execute on growth strategy 6% Peer Average: 5.3% 5% MEP Business Overview 4% • Large scale natural gas/NGL Summit Midstream Access Midstream 3% Targa Resources Regency Energy DCP Midstream QEP Midstream S&P 500 Utilities FTSE NA REIT 10-Yr Treasury Notes midstream business positioned Atlas Pipeline EQT Midstream Western Gas 2% Crestwood Midcoast Markwest in key producing basins S&P 500 EnLink 1% • Offer integrated solutions 0% across the midstream value Midstream MLP’s (1) Other Asset chain Classes (1) (1) Yield as of March 24, 2014 (2) Represents net book value of assets as of December 31, 2013. 4
Enhanced Natural Gas & NGL Midstream Strategic Focus Gas-Focused Operations Liquids-Focused Operations Energy Partners, L.P. “Pure - Play” Natural Gas & NGL Midstream Enhances Strategic Focus of Partnership Increases Ability to Respond to Market Opportunities Enhanced Access to Capital MEP Growth Supported by Drop-Downs 5
Drop-Down of Natural Gas Business 100% Natural Gas business ownership 61% 39% IPO 2014 2017e IPO NTM 9/30/14 2017E MEP EBITDA Growth Through…. MEP to Acquire 100% of Midcoast Operating within 5 years • 1st Drop-down post-IPO targeted mid-2014 ~ $300 – $500 million Secure and execute on ~$1 billion capital growth program through 2017 Positioned for commodity price recovery Deliver Attractive Distribution Growth (1) Compounded annual distribution growth rate. Target annualized minimum quarterly distribution is $1.25/unit. 6
Growth and Development Aligned and Supported by Sponsors Enbridge Inc. (ENB) • A-/Baa1 • $37 billion equity market capitalization Enbridge Energy Partners, L.P. (EEP) • BBB/Baa2 • $11 billion equity market capitalization Support of Strong Sponsors: Financial Support and Risk Management Operational Oversight and Management Major Project Execution and Risk Mitigation Commercial and Investment Review Oversight 65% 62% Note: Standard & Poor’s/Moody’s credit ratings respectively. Market capitalization as Energy Partners, L.P. of March 3, 2014. 7
Lower 48 Natural Gas Production Forecast 110 100 90 BCF/day 80 70 60 50 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Enbridge Jan 2014 PIRA Oct 2013 Wood MacKenzie Nov 2013 CERA Dec 2013 EIA Dec 2013 Robust natural gas production outlook 8
Natural Gas Demand Forecast 70 4 557 266 533 1,770 139 546 223 199 6 3 1,592 2,161 996 35 79 2013-2025 (mmcfd) 354 Coal retirements = 6,617 Industrial = 2,916 Midcoast assets located in single largest demand growth area Source: Wood Mackenzie, November 2013 9
North American LNG Exports to Asia Increase Gas Demand 2016 LNG Exports to Asia North American LNG Exports $16.00 14 Asian Contract Price ($13.43) $14.00 12 $3.07 Netback $2.68 BC exports $12.00 Shipping 10 LNG Shrinkage $10.00 $1.35 (fuel) $0.39 $2.50 8 Liquefaction Bcf/d $8.00 $0.46 $4.00 Pipeline 6 Transport $6.00 $3.00 Gas price US exports 4 $0.10 $1.40 $4.00 2 $4.30 $2.00 $3.61 0 $0.00 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 USGC ($10.36) BC ($10.75) East Texas asset footprint ideally positioned to access LNG export infrastructure Source: Preliminary 2014 Enbridge Fundamentals View, PIRA 10
Strong Production Growth Drives Infrastructure Investment US Midstream Infrastructure Requirements Base Case 120 45 40 100 35 80 30 $ Billions 25 Bcf/d 60 20 40 15 10 20 5 0 0 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Natural Gas / NGL / Crude Oil Rail & Marine Logistics Natural Gas & NGL Processing Natural Gas Gathering, Pipelines & Storage Natural Gas Production Sustained growth opportunities for natural gas infrastructure investment Sources: “Oil & Natural Gas Transportation & Storage Infrastructure: Status, Trends, & Economic Benefits,” IHS, December 201 3 11
North American Production Growth Evolving Change in flows between 2013 and 2018 1.0 WCSB (0.5) 0.5 2.1 Appalachia Rockies 0.5 1.6 LNG Exports 0.6 1.2 (0.5) Red = Decrease (0.5) Mid Continent Blue = Increase 0.4 1.7 0.8 Only Flows > 0.3 Bcf/d shown 0.7 Permian Gulf Coast (0.3) 1.1 2.8 MX 1.5 LNG Source: Preliminary 2014 Enbridge Fundamentals View GoM Exports Exports Offshore Growing northeast production is restructuring the gas markets and enabling exports 12
Large-Scale, Diversified Business Key Assets Natural Gas Deliveries ~ 2.5 bcf/d Anadarko System Gathering and Transportation Pipelines 11,400 miles Processing Capacity (26 plants) 2.3 Bcf/d Treating Capacity (11 plants) 1.3 Bcf/d Texas Express NGL system 35% JV interest Texas Express NGL System East Texas System CLINE SHALE Petal North Texas System EAGLEBINE Logistics and Marketing Assets well positioned to pursue opportunities in emerging growth basins 13
Growth Outlook • Secure and execute on growth opportunities • Leverage existing asset base and pursue step-outs in close proximity • Expand processing capabilities • Pursue accretive acquisitions • Complement and diversify existing asset footprint ~ value chain integration • Longer-term: geographic diversification (i.e. Bakken, Eagle Ford, West Texas, Oklahoma) • Shifting North American supply and demand fundamentals present new opportunities for pipeline infrastructure 14
Strategic Priorities • First drop-down post-IPO expected mid-2014 • Position for future drop-downs • Aggressively pursue and secure organic growth • Enhance value-added services to increase competitiveness of existing supplies • Pursue new business opportunities with low-risk commercial framework • Rationalize existing portfolio • System enhancement and optimization • Redeploy assets to capture new opportunities and enhance returns • Utilize Logistics & Marketing to attract new business to G&P footprint • Leverage first-mover capabilities in greenfield plays leading to infrastructure development • Transition from optimizer to true commercial developer • Manage costs 15
Key Takeaways • Deliver target distribution growth • First drop-down post-IPO expected mid-2014 • Pursue and secure organic growth • Strengthen underlying business performance • Manage and pursue new opportunities - Reduce volume and commodity price sensitivity - Deliver more certain and stable cash flows • Strong natural gas fundamentals backdrop supports continued infrastructure investment Safety and operational reliability are cornerstones that underpin our business and growth outlook 16
NATURAL GAS Terrance McGill, President , Midcoast Energy Partners
Key Messages • Enhance the profitability of our existing assets • Leverage our large and strategically located asset base to pursue attractive organic growth opportunities • Enhanced access to capital positions business to respond to market opportunities • First drop-down post-IPO to MEP mid-2014 Safety and operational reliability are cornerstones that underpin our business and growth outlook 2
Rich Gas Continues to Drive Production in our Regions $/MMcf Illustrative Production Value $14.00 ~12.93 ~$11.96 $12.00 $10.00 $8.00 ~$6.17 $6.00 ~$4.25 $4.00 Nymex = $4.25 $2.00 $- East Texas East Texas Anadarko North Texas Cotton Valley Granite Wash Marble Falls Natural Gas NGLs Condensate Forward prices as of March 14, 2014. NGL and crude oil value will continue to incentivize producers to drill 3
Supply Growth Driven by Liquids Plays Anadarko Production Forecast Barnett Production Forecast Haynesville Production Forecast 10 10 10 Annual Average (Bcf/d) Annual Average (Bcf/d) Annual Average (Bcf/d) 8 8 8 6 6 6 4 4 4 2 2 2 0 0 0 2012 2014 2016 2018 2020 2022 2024 2012 2014 2016 2018 2020 2022 2024 2012 2014 2016 2018 2020 2022 2024 3rd Party Range 3rd Party Range 3rd Party Range Eagle Ford Production Forecast Marcellus/Utica Production Forecast Bakken Production Forecast 10 10 30 Annual Average (Bcf/d) Annual Average (Bcf/d) Annual Average (Bcf/d) 25 8 8 20 6 6 15 4 4 10 2 2 5 0 0 0 2012 2014 2016 2018 2020 2022 2024 2012 2014 2016 2018 2020 2022 2024 2012 2014 2016 2018 2020 2022 2024 3rd Party Range 3rd Party Range 3rd Party Range Pursue rich gas opportunities and basin diversification 4
NGL Production Growth Strong NGL supply outlook supports continued infrastructure and services growth Source: PIRA “Global NGL Markets and the Growing Role of North America” ( Oct 10, 2013) 5
NGL Demand Outlook 1,800 Ethane Propane 2,000 1,600 exports 1,400 ethylene feedstock 1,500 1,200 MB/D 1,000 industrial and other MB/D exports markets 800 1,000 ethylene feedstock refinery propylene to chem 600 400 500 propane dehydro 200 0 motor fuel 0 2010 2015 2020 2025 2010 2015 2020 2025 600 500 Butane Natural Gasoline exports 450 500 exports 400 misc. markets 350 misc. markets 400 transfers to private 300 MB/D ethylene feedstocks MB/D storage 250 300 other chemical ethanol denaturant 200 ethylene feedstock 150 crude blending 200 100 gasoline blenders Dehydro MTBE 50 100 refinery inputs merchant isom units 0 2010 2015 2020 2025 0 2010 2015 2020 2025 Improving NGL price outlook as exports complement domestic demand Source: Petral Annual Forecast, August 2013 6
Natural Gas and NGL Midstream Business Anadarko System Ajax Processing Plant in service 3Q 2013 Texas Express NGL System East Texas System In service 4Q 2013 Beckville Processing Plant expected in service 1Q 2015 CLINE SHALE North Texas System Petal Marble Falls Associated Rich Gas EAGLEBINE Logistics and Marketing 250 transport trucks, 300 trailers, 205 rail cars, TexPan Liquids Rail Facility 100,000+ Bpd of long-term fractionation capacity secured 7
Rig Counts Holding Steady Anadarko 6-County Rig Count, 52-Weeks (RigData) 160 Rigs Well Starts Permits 140 120 100 80 60 40 20 - MAR 22 APR 12 MAY 03 MAY 24 JUN 14 JUL 05 JUL 26 AUG 16 SEP 06 SEP 27 OCT 18 NOV 08 NOV 29 DEC 20 JAN 10 JAN 31 FEB 21 MAR 14 Petal Fort Worth Basin Rig Count, 52-Weeks (RigData) 350 Rigs Well Starts Permits 300 250 200 150 100 50 0 MAR 22 APR 12 MAY 03 MAY 24 JUN 14 JUL 05 JUL 26 AUG 16 SEP 06 SEP 27 OCT 18 NOV 08 NOV 29 DEC 20 JAN 10 JAN 31 FEB 21 MAR 14 Recent permitting uptick across asset footprint 8
Anadarko System – Strategically Located in Texas Panhandle and Western Oklahoma Processing Plant Highlights Treater Plant Gas Pipeline Active rigs 53 rigs (1) Liquids Pipeline Texas Express Rigs drilling on 18 rigs (2) dedicated acreage Miles of natural gas gathering and ~2,950 miles transporting pipelines Wells connected to ~3,600 wells (3) delivery receipt points on system 12 plants (4) Processing plants Processing 1,115 MMcf/d capacity (1) Source: RigData. Rig count as of week of March 7, 2014. (2) As of February 28, 2014. (3) As of June 30, 2013. (4) Includes three standby processing plants. Cline Shale Mississippi Lime Premier position in rich gas basin 9
East Texas System – Extensive Footprint in East Texas: Haynesville & Cotton Valley Processing Plant Highlights Treater Plant 58 rigs (1) Active rigs Gas Pipeline Rigs drilling on dedicated Liquids Pipeline 21 rigs (2) acreage Miles of natural gas gathering and transporting ~3,850 miles pipelines Wells connected to delivery ~5,600 wells receipt points on system Processing plants 7 plants (3) 885 MMcf/d (3) Processing capacity 11 plants (4) Treating plants 1.3 Bcf/d (4) Treating capacity Fractionation facilities 1 facility Fractionation capacity ~3,000 Bpd East Texas Basin (1) Source: RigData. Rig count as of week of March 7, 2014. Haynesville Shale (2) As of February 28, 2014. (3) Includes two HCDP plants. Includes Beckville plant, which is under Cotton Valley construction and is expected to commence service in early 2015. Eaglebine (4) Includes one standby treating plant. Strategically positioned to expand footprint into emerging basins 10
North Texas System – Extensive Asset Footprint Processing Plant Highlights Gas Pipeline Liquids Pipeline 42 rigs (1) Active rigs Texas Express Rigs drilling on dedicated 4 rigs (2) acreage Miles of natural gas gathering and 4,600 miles transporting pipelines Wells connected to ~3,400 wells delivery receipt points (2,258 receipt points) (3) on system 7 plants (4) Processing plants 275 MMcf/d (4) Processing capacity Stabilizers 1 stabilizer Stabilizer capacity 4,000 Bpd Barnett Dry Gas Barnett Rich Gas (1) Source: RigData. Rig count as of week of March 7, 2014. Barnett Oil (2) As of February 28, 2014. (3) As of June 30, 2013. Marble Falls (4) Includes one standby processing plant. Established operator; positioned to secure growth opportunities 11
Texas Express NGL System Description of Assets Strategic Benefits • Addresses Mid-Continent, Rockies and West Texas NGL • NGL Mainline System constraints • JV with Enterprise Products Partners (35%, operator), • Enhances our competitive position by providing greater Midcoast Operating (35%), Anadarko Petroleum access to Mont Belvieu fractionation Corporation (20%) and DCP Midstream (10%) • 580-mile, 20-inch NGL pipeline originates from Texas Express Footprint Skellytown, TX to Mont Belvieu NGL hub • Initial capacity of ~280,000 Bpd; expandable to New NGL Gathering Skellytown ~400,000 Bpd • NGL Gathering Systems • JV with Enterprise (45%), Midcoast Operating (35%, operator) and Anadarko (20%) Mainline System Volume Commitments Dallas 200,000 150,000 100,000 50,000 Mont Gathering Pipelines Under Construction Belvieu - Texas Express Mainline Houston Gathering Pipelines U nder Construction Texas Express Mainline Proposed Gathering Pipelines Proposed Gathering Pipelines 2014E 2105E 2016E 2017E Midcoast All Other Shippers Participation in NGL value chain - secures long-term demand-based cash flows 12
Understanding Volume Trends • Substituting rich gas for dry gas • Producers drilling wells, delaying completions Illustrative Production Values 10,000 1,400 10,000 1,200 Type Curve (Mcf/d) Type Curve (Mcf/d) Type Curve (Mcf/d) 8,000 8,000 1,000 6,000 6,000 800 600 4,000 4,000 400 2,000 2,000 200 - - - 1 6 11 16 21 26 31 36 41 46 51 56 1 6 11 16 21 26 31 36 41 46 51 56 1 6 11 16 21 26 31 36 41 46 51 56 Month Month Month Marble Falls Barnett Granite Wash Hogshooter Cotton Valley Haynesville 13
Business Opportunities: Gathering, Processing & Transportation Actionable Growth Opportunities • Capture rich gas opportunities • New pipeline laterals, NGL laterals, and compression projects • Expand processing capabilities System Optimization • Maximize throughput and NGL production - Ramp-up of Texas Express and Ajax • Plant upgrades CLINE SHALE • System capabilities enhance operational flexibility and reliability EAGLEBINE COTTON VALLEY - Daily dispatch to route rich gas to most efficient plants Leverage existing capabilities to increase reach both inside and outside of current asset footprint 14
Business Opportunities: Logistics & Marketing TexPan Rail Growth Oriented Value Added Midstream Solutions • Expand takeaway solutions for customers • Bundled service offerings • Access premium markets to enhance customer netback • Leverage “first -mover ” advantage capabilities in emerging basins Transform Logistics & Marketing from optimizer to true commercial developer 15
Organic Projects Support Distribution Growth Incremental Growth Expected Description Cost Timing 2014 2017 2015 2016 • 150 MMcf/d cryogenic processing plant with In-service in a ~2,000 Bpd condensate stabilizer $230 million Ajax Plant Q3 2013 • Ramp-up through early 2014; 2015 the first full year of contribution • NGL Mainline: 580-mile, 280,000 bpd NGL pipeline from Skellytown, TX to Mont Belvieu; In-service in Texas $400 million (1) 10 year ship-or-pay contracts with 5 year Q4 2013 dedication Express • Gathering: 116 miles of pipeline • Full ramp-up expected over time • Provide processing to rich Cotton Valley gas • Capacity of ~150 MMcf/d and 8,500 Bpd of Beckville In-service in ~$145 million NGLs early 2015 Plant • Ramp-up throughout 2015; 2016 the first full year of contribution • Extend asset reach into Eaglebine and Cline • Plant upgrades Unsecured • Compression projects 2014 and Growth ~$250 million/yr • NGL injection terminals and NGL pipelines beyond Projects • Expand condensate and liquids handling and takeaway • Small-scale acquisitions 16 (1) Represents MEP’s 35% interest in the Texas Express NGL System joint venture.
Safety and Operational Reliability • Comprehensive Integrity Management Program • Increased line patrols, in-line inspections and incident response capabilities • Control center enhancements • Installation of EFRD (emergency flow restricting devices) to protect HCAs on liquids and gas transmission lines • Implementation of industry leading best practices • Strengthened the safety culture Industry leader in integrity management 17
Key Takeaways • Enhance the profitability of our existing assets • Enhance value of first and prospective drop-downs • Leverage our large and strategically located asset base to pursue attractive organic growth opportunities • Enhanced access to capital positions business to respond to market opportunities • Attractive entry point in commodity price cycle Safety and operational reliability are cornerstones that underpin our business and growth outlook 18
FINANCE – EEP Steve Neyland, Vice President, Finance
Key Messages • Long term value proposition Attractive yield combined with significant tax deferral Sustainable distribution Strong investment grade credit rating • Secured Liquids projects collectively further transform the Partnership to lower risk business model Distribution coverage strengthens as projects enter service • Manageable funding outlook and growing financial strength • Targeting 2% to 5% annual distribution growth • Attractive long-term growth outlook Bolstered by asset drop-down potential by General Partner 2
Delivering Prudent Growth - Liquids Attractive suite of low risk, fee-based organic growth secured Net Capital Capital Target EBITDA multiple (4) ($MM) Cost EEP In-Service Risk Profile Bakken Growth Projects Long-term Ship-or-Pay/Cost of Sandpiper (1) 2,600 1,625 early 2016 7x Service Eastern Access (1) 30 year Cost of Service Line 5, Line 62 expansion In-Service 2013 2,100 525 9x Line 6B Replacement 2Q14 – 3Q14 Highly certain cash flows Line 6B Expansion + tankage 400 100 early 2016 8x US Mainline Expansion (1) No volume risk Phase 1 3Q14; Line 67 (Border to Superior) (3) 1,900 475 5x Phase 2 2015- Line 61 (Superior to Flanagan) 2016 No capital risk (2) Chicago Connectivity (Line 62 twin) 500 125 2H 2015 8x Line 3 Replacement (1) 2,600 1,300 2H 2017 8x $10,100 $4,150 (1) Eastern Access, Mainline Expansion projects and Line 3 Replacement to be jointly funded by EEP & ENB. Sandpiper construction to be funded 37.5% by Marathon Petroleum Corp. (2) Eastern Access has modest capital cost risk. (3) Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions. (4) Represents first full year EBITDA contribution. 3
Risk Profile – Lower Risk Business Model Crude oil projects progressively transform EEP to lower risk business model 2017e Unconsolidated View 2015e 32% 2013 27% 2008 18% Cost of Service/Take-or-Pay : Contribution from Liquids and Natural Gas business cost of service and take-or-pay contracts. Fee-based: Contribution from Liquids and Natural Gas business fee-based service. Commodity Sensitive : Contribution from Natural Gas business commodities length (before hedging). Contribution is based on revenues from Liquids segment and gross margin from Natural Gas segment, excluding non-controlling interest. 4
Capital Forecast and Liquidity Position Manageable capital expenditures outlook complemented by strong liquidity position Net Capital Forecast (2014- 2017) * Liquidity Position 12/31/2013 $5,000 $3,000 0.4 $2,628 0.3 165 $2,500 $4,000 1.2 $ millions $2,000 $3,000 $1,500 $ millions ~ $5.1 billion 2,463 Net of Joint $1,000 3.2 Funding $2,000 $500 $0 $1,000 Available Liquidity Credit Facilities Cash $0 $3.175 billion Committed Credit Facilities 2014e - 2017e Maintenance capital Natural Gas $1.5 billion Commercial Paper Program Integrity capital and other growth Liquids secured growth * Liquids capital expenditure forecast is net of the Joint Funding Agreements with Enbridge Inc. and Marathon Petroleum 5 Corporation. Natural Gas capital expenditures net of funding with Midcoast Energy Partners, L.P.
Joint Funding Agreements Joint funding enhances Partnership’s financing flexibility Enbridge Inc. Joint Funding EEP Funded ENB Funded MPC Funded Eastern Access and US Mainline Expansions Eastern Access $1,225 • Enbridge Inc. to fund 75% of projects ~ in form of 100% equity investment $3,675 Mainline Expansions • EEP has separate options to upsize interest by up to 15% one year from last in-service date Net Line 3 Replacement Capital $1,300 $1,300 Line 3 Replacement To EEP • Project to be jointly funded with Enbridge Inc.* $4,150 Marathon Petroleum Corp. Joint Funding Sandpiper $975 Sandpiper $1,625 • Marathon Petroleum Corp. will fund 37.5% of Project Sandpiper construction costs. ** $ millions *Assumed 50% joint funding participation levels to be finalized by a Special Committee of the independent Board of 6 Directors. **Marathon Petroleum Corp. will fund 37.5% of Project Sandpiper cost and assume a ~27% equity interest in the EEP North Dakota system, once the project enters service.
2014 EBITDA Guidance (unconsolidated) Strengthening results supported by strong fundamentals & market access projects cash flows Strong supply & demand outlook 250 Full year 2013 projects 1,300 2014 projects in-service 88 $1,000 $ millions 1,055 2014 EBITDA Growth: • Lakehead + ~$110MM • North Dakota + ~$95MM • Eastern Access + ~$35MM • Mainline Expansions + ~$5MM $0 2013 2014e Noncontrolling Interest* * Noncontrolling interest attributable to projects jointly funded with Enbridge Inc. Also includes noncontrolling interest attributable to Midcoast Energy Partners. L.P. 7
EBITDA Growth Outlook (unconsolidated) EBITDA growth underpinned by projects with low risk commercial framework Sandpiper FY Eastern Access Mainline Exp Visible Cash Flow Growth Sandpiper L3R $3,000 Eastern Access Mainline Exp Eastern Access Mainline Exp $2,000 Eastern Access Mainline Exp $ millions North Dakota FY 250 88 1,300 $1,000 1,055 $0 2013 2014e 2015e 2016e 2017e Noncontrolling Interest* * Noncontrolling interest attributable to projects jointly funded with Enbridge Inc. and Marathon Petroleum Corp. equity 8 interest in EEP North Dakota System. Also includes noncontrolling interest attributable to Midcoast Energy Partners. L.P.
Strengthening Distribution Coverage Secured growth projects improve distribution coverage 1.25x Long Range Coverage Target 1.00x Accretive growth underway 0.75x Coverage* Backed by long-term, low risk commercial framework • cost-of-service 0.50x • ship-or-pay 0.25x Highly certain distributable cash flow growth 0.00x 2010 2011 2012 2013 2014e 2017e * Coverage includes EEQ paid-in-kind distribution. Guidance range 9
Operational Reliability Liquids Integrity Capital* $600 Liquids Integrity Capital Expenditures: $500 Sleeving pipeline segment Cut-out & replace pipeline segment $400 $ million Recoating pipeline segment $300 Recoverability : $200 Engage shipper group annually to recover a portion of integrity capital through toll structure $100 $0 2008 2009 2010 2011 2012 2013 2014e 2015e 2016e 2017e * Integrity capital expenditures do not include Line 6B replacement and planned Line 3 replacement program. New or modified requirements could impact our future integrity costs. 10
Funding Plan 2014-2017 (unconsolidated) Equity funding requirements manageable ($billion) Uses/(Sources) Secured Growth Capital 9.4 Maintenance Capital 0.4 Joint Funding Call Back on Lakehead Expansions 0.7 10.5 ENB Joint Funding* (3.3) Sandpiper Joint Funding (1.0) MEP Drop-Downs +/- (2.6) Net Funding Required 3.6 Debt Equity Total Requirement 2.4 Total Requirement 1.2 2014 – 2017 Maturities 0.9 EEQ PIK (0.6) Debt Requirement 3.3 Equity Requirement 0.6 Financing Options Additional MEP Drop-Downs Additional MEP Drop-Downs Bank Credit Facility Hybrid Securities Floating Rate Note Private Placement Term Debt ATM program Hybrid Securities EEP/EEQ Common Unit Offering * Joint funding with Enbridge Inc. includes estimated 50% funding by Enbridge Inc. for U.S. component of Line 3 11 Replacement program and 50% estimated funding by EEP. Participation levels being finalized and approved by Independent Special Committee.
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