Eep2013 investordaypresentation

  • 1,756 views
Uploaded on

 

  • Full Name Full Name Comment goes here.
    Are you sure you want to
    Your message goes here
    Be the first to comment
    Be the first to like this
No Downloads

Views

Total Views
1,756
On Slideshare
0
From Embeds
0
Number of Embeds
1

Actions

Shares
Downloads
3
Comments
0
Likes
0

Embeds 0

No embeds

Report content

Flagged as inappropriate Flag as inappropriate
Flag as inappropriate

Select your reason for flagging this presentation as inappropriate.

Cancel
    No notes for slide

Transcript

  • 1. Agenda8:30 - 9:00 am Breakfast 1 0:55 - 11:25 am Natural Gas John Loiacono VP Commercial Activities,9:00 - 9:05 am Introduction Natural Gas Director Sanjay Lad, Gathering and Processing, Investor Relations, Enbridge Energy Partners Enbridge Energy Partners 11:25 - 11:55 am Finance9:05 - 9:30 am Strategic Overview Steve Neyland VP Finance, President Mark Maki, Enbridge Energy Partners Enbridge Energy Partners 11:55 - 12:00 pm Closing Remarks9:30 - 10:40 am Liquids Pipelines President, Mark Maki, Stephen Wuori, President, Enbridge Energy Partners Liquids Pipelines, Enbridge Inc. 12:00 - 1:00 pm Lunch10:40 - 10:55 am Break Olmstead Room Enbridge Energy Partners, L.P. Enbridge Energy Management, L.L.C.
  • 2. Sanjay Lad, Director, Investor RelationsIntroduction
  • 3. Legal Notice This presentation includes certain forward looking information (“FLI”) to provide Enbridge Energy Partners, L.P. (“EEP”) and Enbridge Energy Management, L.L.C. (“EEQ”) investors and potential investors with information about EEP and EEQ and management’s assessment of the future plans and operations, which may not be appropriate for other purposes. FLI involves statements that frequently use words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “should,” “strategy,” “will” and similar words. Although we believe that such forward looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond Enbridge Partners’ ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) changes in the demand for or the supply of, forecast data for and price trends related to crude oil, liquid petroleum, natural gas and NGLs, including the rate of development of the Alberta Oil Sands; (2) Enbridge Partners’ ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline systems; (4) shut-downs or cutbacks at facilities of Enbridge Partners or refineries, petrochemical plants, utilities or other businesses for which Enbridge Partners transports products or to whom Enbridge Partners sells products; (5) hazards and operating risks that may not be covered fully by insurance; (6) changes in or challenges to Enbridge Partners’ tariff rates; and (7) changes in laws or regulations to which Enbridge Partners is subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance. Our FLI is subject to risks and uncertainties pertaining to operating performance, regulatory parameters, project approval and support, weather, economic conditions, interest rates and commodity prices, including but not limited to those discussed more extensively in our filings with U.S. securities regulators. The impact of any one risk, uncertainty or factor on any particular FLI is not determinable with certainty as these are interdependent and our future course of action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law, we assume no obligation to publicly update or revise any FLI, whether as a result of new information, future events or otherwise. All FLI in this presentation is expressly qualified in its entirety by these cautionary statements. You are referred to EEP’s and EEQ’s SEC filings, including its most recently filed Annual Report on Form 10-K, for a more detailed discussion of risk factors. This presentation makes reference to certain financial measures, such as adjusted net income, which are not recognized under generally accepted accounting principles, referred to as GAAP. 2
  • 4. Mark Maki, PresidentStrategic Overview
  • 5. Key Messages• System integrity, safety and project execution are top priorities• Unrivaled Liquids pipeline asset position in infrastructure MLP arena • ~$7.3 billion organic expansion secured in 2012/2013 • Low risk business growth • Supports 2% to 5% annual distribution growth target• Execute growth program • Project execution • Financial execution• Attractive yield 2
  • 6. Corporate Structure ENB* Enbridge Inc. Enbridge Inc. owns • Yield: 2.9% (NYSE: ENB) ~22% of EEP • 10-yr TSR: 19% • EV: $62B 100% Indirectly Owned Enbridge Energy Company, Inc. 100% 16.8% Voting Shares Listed Shares 2% Enbridge Energy General Partner Management, L.L.C. EEQ* • Yield: 7.6% Interest (NYSE: EEQ) Public • 10-yr TSR: 15% 83.2% • EV: $1.2B And Management 13.5% Limited Partner 17.5% and Control Interest (I Units) Limited Partner Interest Enbridge Energy EEP* Partners, L.P. Public • Yield: 7.8% (NYSE: EEP) 67.0% • 10-yr TSR: 11% • EV: $13.1B Ownership as of February 14, 2013. Does not include recent EEQ public offering launched 2/25/2013. *yield as of 2/22/2013; EV and TSR (nominal CAGR) as of 12/31/2012. 3
  • 7. Investment Thesis 4
  • 8. Strength of GP – Enbridge Inc.  ~$35 billion equity market cap  Strong investment grade  Proven track record: industry leading EPS and DPS growth • 5 year EPS CAGR of 13% • 5 year DPS CAGR of 13%  Strategy aligned with Partnership  Joint funding provides Partnership financing flexibility 19% 62% 65% 5
  • 9. Attractive Investment Proposition Attractive Yield • One of the longest serving pipeline MLPs (1991) • Attractive return CAGR10% • Track record of consistently delivering cash EEP: 7.8% distributions 9% • Prudent growth 8% Total Shareholder Return 7% $180,000 Peer average: 6.1% 6% $160,000 5% $140,000 4% $120,000 $100,000 Magellan Midstream Plains All American 3% Notes Sunoco Logistics Energy Transfer S&P 500 Utilities $80,000 Kinder Morgan FTSE NARIET 2% 10-Yr Treasury Boardwalk Enterprise $60,000 S&P 500 Buckeye Williams Nustar Oneok 1% $40,000 EEP 0% $20,000 Other Asset $0 MLPs* Classes** 1991 2012* As of February 22, 2013** Return CAGR since inception (nominal) 6
  • 10. Strategic PositionPremier asset position Crude oil pipeline and storage systems deliver ~ 2.5 million barrels/day Natural gas gathering, processing & treating systems deliver ~ 2.5 billion cubic feet/day Lakehead System North Dakota System Midcontinent System EEP Liquids Pipelines ENB Liquids Pipelines and Joint Ventures EEP Natural Gas Pipelines EEP NGL Pipeline Joint Venture 7
  • 11. Potential North American Crude Oil Supply Balance Domestic production growth provides opportunity to displace foreign sourced crude oil North American Demand by Supply Source North American Supply MMbpd 18 16 U.S. Consumption Foreign 14 Foreign High Shale Forecast Foreign 12 High Shale Forecast 10 Transportation Bottlenecks U.S. 8 U.S. 6 U.S. 4 Canadian 2 Canadian Canadian Enbridge Market Access 0 2010 2015 2020 (pipeline connectivity) Source: Enbridge Internal Forecast 8
  • 12. Growth Strategy  Expand Liquids Pipelines systems • New infrastructure and market access • Expand and enhance reliability of existing infrastructure • Highly certain returns and long term cash flows  Strengthen Natural Gas business • Diversify within existing basins (rich gas, dry gas, off-spec) • Expand participation in NGL and Natural Gas value chain • Optimize performance of business unit  Position the Partnership as a drop-down vehicle for Enbridge Inc. • Attractive suite of drop-down assets 9
  • 13. Secured Growth Program Underway Liquids Pipelines Growth Projects • Secured $7.3 billion of incremental growth in 2012/2013 • Eastern Access  Line 5 expansion, Line 6B replacement, Line 62 expansion • Mainline Expansions (USGC Access)  Line 67 expansion, Line 61 expansion, Line 62 twin • Light Oil Market Access  Sandpiper pipeline Natural Gas Growth Projects • Expand processing capacity  Allison 150 MMcf/d plant 2012; Ajax 150 MMcf/d plant mid 2013 • Value chain integration  Texas Express NGL Pipeline JV 3Q13  Increase fractionation capacity • Expand condensate handling capabilities  Condensate stabilization; condensate take-away strategy 10
  • 14. Business Mix & Risk ProfileCrude oil projects progressively transform EEP to lower risk business model 100% Operating Income* 23% Commodity 12% 80% 28% Fee-Based 60% Liquids Natural Pipelines Gas 59% 80% 20% 40% 60% 20% Cost of Service /*Note: based on 2013 forecast 18% Take-or-Pay 0% 2008 2009 2010 2011 2012 2013 2014 2015 2016 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 from its commodities length (before hedging). Contribution is based on revenues from Liquids segment and gross margin from Natural Gas segment, including non-controlling interest. 11
  • 15. Distribution Growth Target Organic growth platform supports distribution growth 2.7% 4.2% - 3.8% 3.6% 2.1% 2007 2008 2009 2010 2011 2012 2016e 12
  • 16. Operational Excellence & Project Execution Operational Project Excellence Execution Project Development Third Party Damage Avoidance and Incident Response Detection Capacity Supply Chain Management Leak Detection Employee and Capability and Contractor Control Systems Occupational Safety Major Life Cycle Gating Control Projects Construction Industry Public Safety and Integrity Environmental Experience Management Leadership Protection Regulatory & PermittingOrganizational commitment to being “best in class” Proven track record: on-time & on-budget 13
  • 17. Key Takeaways • System integrity, safety and project execution are top priorities • Secured Liquids projects collectively further transform the Partnership to lower risk business model • Distribution growth: targeting 2% to 5% annual growth target • Growth trajectory in Liquids business will bolster distribution growth • Visible growth and attractive long-term outlook • Maintaining investment grade credit rating is a priority 14
  • 18. Stephen Wuori, President, Liquids PipelinesLiquids Pipelines
  • 19. Key Messages • Operational excellence, system integrity, safety and project execution are top priorities • North American crude oil supply picture is robust • Crude oil price differentials support significant additional infrastructure • Project implementation and integration is on track • Enbridge will continue to be the premier liquids pipeline system to provide access to multiple premium markets 2
  • 20. Strategic Position & EEP Competitive Advantage Norman Wells • Strong GP – Enbridge Inc. Zama • Strategic Asset Base Fort McMurray  Connected to rapidly growing Edmonton supply sources Hardisty Regina Cromer St. John  Access to premium marketsSeattle Clearbrook Montreal Ottawa Portland Superior Toronto Buffalo Sarnia Philadelphia Casper Toledo Flanagan Chicago Salt Lake City Patoka Wood Cushing River Enbridge Inc. Liquids Assets EEP Liquids Assets St. James Key Production Regions Houston 3
  • 21. North American Crude Supply Growth (2020) MMbpd 3.5 3.0 Other 2.5 Cardium/Viking/Duvernay 2.0 Niobrara 1.5 Bakken US 1.0 Eagle Ford Oil Sands 0.5 Permian 0.0 Heavy Light • ~ 4.5 million bbls per day of potential growth in North America • Light oil growth set to outpace heavy oil growth 4
  • 22. North American Demand by Supply Source 20 15 Foreign Foreign High Shale Forecast Foreign High Shale ForecastMMbpd 10 U.S. U.S. 5 U.S. Canadian Canadian Canadian 0 2010 2015 2020 Source: Enbridge Internal Forecast North American production provides significant opportunity to displace foreign sourced crude oil 5
  • 23. Commodity Price Fundamentals DrivingMarket Access Strategy Light Differentials Asia Brent - WTI $22 $124 Asia - WTI $29 $90 Alberta Light $110 WCS LLS - WTI $22 $69 WTI - Bakken $1 $94 Bakken WTI - Alberta $5 $117 Brent Light WTI Heavy Differentials $95 Light Crude Maya- WCS $36 Maya LLS $117 Heavy Crude Asia - WCS $41 $105 North American Supply North American Demand Transportation Bottlenecks Significant Infrastructure Investment OpportunitiesFebruary 20, 2013 prices (in US$/bbl) 6
  • 24. Western US Gulf Coast Access 1 Chicago/ Flanagan 21 Associated Mainline Expansion • In-service = Various (2014 – 2015) Cushing2 Flanagan South Pipeline • In-service = mid 2014, +585 kbpd 3 Western USGC Refining Processing Capability3 Seaway Pipeline Acquisition & Reversal 4 • In-service = May 2012, +400 kbpd Heavy4 Seaway Pipeline Twin & Lateral Light 43% Port Arthur 57% • In-service = mid 2014, +450 kbpd Houston W USGC ~ 4,400 kbpd Source: EIA and Enbridge’s internal estimates 7
  • 25. Eastern US Gulf Coast Access - Trunkline JV Mississippi River Refinery Capacity Superior Exxon Mobil (Baton Rouge) 503 Marathon (Garyville) 490 Valero (Norco) 250 ConocoPhillips (Belle Chase) 247 Motiva (Convent) 227 Motive (Norco) 220 Flanagan Chalmette 189 Valero (Meraux) 135 Southern Alon USA (Krotz Springs) 83 Access Placid (Pt Allen) 56 Extension Shell (St. Rose) 55 Patoka Alabama / Mississippi Refinery Capacity Memphis Chevron (Pascagoula) 330 Shell (Saraland) 85 Hunt (Tuscaloosa) 72 Gulf Atlantic (Mobile) 20 Reversed Trunkline St. James E USGC ~ 3,200 kbpd Source: EIA and Enbridge’s internal estimates 8
  • 26. Eastern Access Hardisty Regina Gretna Montreal Clearbrook Superior 1 Westover1 Line 5 Expansion Sarnia • In-service = early 2013, +50 kbpd Chicago Toledo 52 3 Spearhead North Expansion Flanagan • In-service = early 2014, +105 kbpd 23 Line 6B Replacement • In-service = early 2014, +260 kbpd4 Line 9 Reversal • In-service = mid 2013 / mid 2014, +240 kbpd5 Toledo Pipeline Partial Twin • In-service = early 2013, +80 kbpd Cushing 9
  • 27. Light Oil Market Access Hardisty 1 Gretna Montreal Clearbrook 21 Canadian Mainline Terminal Capability Superior • In-service = mid 2015/early 20162 Sandpiper Project • In-service = early 2016, +225/375 kbpd Sarnia3 U.S. Mainline Expansion a) Superior to Flanagan Toledo Chicago • In-service = mid 2015/early 2016, +800 kbpd Flanagan b) Chicago Area Connectivity 5 • In-service = mid 2015, +570 kbpd Patoka4 Eastern Access Upsize a) Line 6B Expansion • In-service = early 2016, +70 kbpd b) Line 9 Reversal Expansion Cushing • In-service = mid 2014, +80 kbpd5 Southern Access Extension • In-service = early 2015, +300 kbpd 10
  • 28. Bakken Expansion – Sandpiper Pipeline Next phase of pipeline expansion secured: pipeline takeaway to reach 580 kbpd Regional Pipeline Takeaway Enbridge Mainline System • EEP North Dakota Pipeline Capacity Alliance Pipeline Saskatchewan Saskatchewan System (ENF) • 235 kbpd current North Dakota System • Bakken Expansion +120 kbpd (1Q13) Bakken Pipeline Expansion • Sandpiper Project (2016) Bakken Access Program • + 225 kbpd to Clearbrook Berthold Rail Program • + 375 kbpd Clearbrook to Superior Sandpiper Pipeline Regional Rail Takeaway & Delivery Weyburn • Bakken Berthold Rail +80 kbpd (1Q13) • Philadelphia Rail JV + 80 kbpd (ENB) Cromer Steelman Regional Gathering Lignite • Bakken Access +100 kbpd (mid 2013) Gretna Tioga Stanley Minot Berthold Clearbrook to Superior 11
  • 29. Matching North American Crude Supply Growthto Refining CentersGrowth Projects: Montreal Commercially secured 1 2 Low-risk framework EEP North Dakota System 4 5 Long-term contracts Superior 3 Sarnia 6 5 4 Canadian/U.S. East Chicago/ Coast Refinery MarketsEnbridge Energy Partners Projects (EEP) ~ $7.3B* 6 Flanagan Sandpiper Pipeline Project ($2.5B) Patoka1 • +225/375 kbpd early 2016 2 U.S. Mid-West Refinery Markets US Mainline Expansions ($2.4B):2 Line 67 Expansion (border to Superior) • +350 kbpd, total 800 kbpd; 3Q14 to 2015 Cushing3 Line 61 Expansion (Superior to Flanagan) Memphis Enbridge Inc. Projects (ENB) • +800 kbpd, total 1,200 kbpd; 3Q14 to 2016 1 Seaway Pipeline - ENB and EPD JV5 Chicago Connectivity 1 • +400 kbpd 1Q13 • +570 kbpd Line 62 twin mid-2015 7 2 Flanagan South Pipeline Eastern Access Expansions ($2.4B): 3 • +585 kbpd (36” line) mid-20144 Line 5 Expansion 3 Seaway Pipeline Twin & Lateral • +50 kbpd early 2013 Port • ENB and EPD JV; +450k bpd mid-20145 Line 62 (Spearhead North) Expansion Arthur 4 Toledo Pipeline Partial Twin • +105 kbpd early 2014 • +80 kbpd 20136 Line 6B Replacement Houston St. James 5 Line 9 Reversal & Expansion • +260 kbpd 2014; +70 kbpd early 2016 • +240 kbpd late 2013; +80 kbpd 2014 6 Southern Access Extension  Eastern Access & US Mainline Expansions • +300 kbpd Q1 2015 EEP/ENB joint funded U.S. Gulf Coast 7 Trunkline JV Refinery Markets* Represents total capital before joint funding • +440 to 660 kbpd 2015 12
  • 30. Timely Access to Premium Crude Oil Markets ~ 1.7MMbpd of new market access will significantly alleviate market price dislocations Fort McMurray Edmonton Hardisty Kerrobert 2014 Regina Cromer +300 kbpd Brent Gretna Montreal Clearbrook Buffalo 2013 Sarnia +80 kbpd Brent Chicago/ Toledo Flanagan 2014 2015 +600 kbpd Patoka +300 kbpd Cushing LLS 2015 +440 kbpd Port Arthur Houston St. James Maya LLS 13
  • 31. Rail Outlook • Rail is supported in the near term by extended price differentials • Interim access until pipelines are built • Access to markets not accessible by pipe in the longer run • Draw volumes on existing pipelines Loading Offloading Opportunities 14
  • 32. Execute Growth Plan Major Projects - state of the art cost and schedule estimating and management processes Project Development • Consistent & accurate estimates • Standardized design • Front end planning Major Projects Supply Chain • Frame agreements • Dedicated mill space & transparent prices • Leverage portfolio Control • Life cycle gating control • $24+ B of projects under • Advanced cost & schedule controls • Proactive risk management management • ELT & Board of Directors oversight • ~1,150 FTE’s Construction • Industry-leading safety record • Deep field experience • Robust quality control of materials & construction 15
  • 33. Major Projects Execution Status Update Demonstrated track-record: on-time and on-budget execution Expected Cost ScheduleProjects Cost In-service Date Indicator Indicator ($ million) Bakken Pipeline Expansion $300 Q1 2013 Below Budget On Time Berthold Rail $145 PH1 In-service; PH2 Q1 2013 On Budget On Time Line 6B 75-Mile Replacement $317 Q2 2013 On Budget Delayed* Program Eastern Access – Line 5, Line 62 Expansion, Line 6B $2,000 Q1 2013 - Early 2014 On Budget On Time Replacement Eastern Access Upsize – Line 6B $364 Q1 2016 On Budget On Time Expansion U.S. Mainline Expansions – PH1 Q3 2014; Alberta Clipper & Southern $1,910 On Budget On Time PH2 Mid 2015 - Early 2016 Access Expansions U.S Mainline Expansions – Chicago Area Connectivity $495 Mid 2015 On Budget On Time (Line 62 Twin) Sandpiper $2,500 Early 2016 On Budget On Time * Delay due to permitting 16
  • 34. Focus on Operations Our objective is to be the industry leader across critical safety and integrity dimensions Organizational Third Party Damage• Executive Oversight (OIC) Avoidance and Detection Incident Response Capacity• Leadership accountabilities redefined Employee and• Technical staff expanded Leak Detection Capability and Contractor Control Systems Occupational Safety Operational Risk Management Plan Industry Public Safety and Integrity Environmental• Detailed road map to industry leadership Management Leadership Protection position• External expert verification process• Full resourcing provided 17
  • 35. Enterprise Risk Management & Integrity• Inline inspection (ILI)  16,000 km inspected in 2011/2012 More than 4,000 pipe joints examined Medical imaging technology – scan every 3 mm• Hydro testing  Pipe manufacture, pipeline commissioning, ILI verification study per regulator• On-line sensors  Pressures/cycling, pipe movement, external & internal corrosion, vibration• Surveys  Pipe depth, river crossing and geotechnical conditions, corrosion control, 3rd party activity• Non-destructive testing  Targeted investigation sites• Equipment checks  Seals, sumps, rotating equipment 18
  • 36. Pipeline Safety – Leak Detection Overlapping Leak Detection • Computational Pipeline Monitoring • Line balance calculations • Operator monitoring • Visual surveillance Detection Improvements • Monitoring system tuning • $190 million instrument adds • Dynamic alarm thresholds Multipath Ultrasonic Flow Meter 19
  • 37. Key Takeaways • Operational excellence, system integrity, safety and project execution are top priorities • North American crude oil supply picture is robust • Crude oil price differentials support significant additional infrastructure • Project implementation and integration is on track • Enbridge will continue to be the premier liquids pipeline system to provide access to multiple premium markets 20
  • 38. John Loiacono, VP Commercial, Natural Gas G&PNatural Gas
  • 39. Key Messages • Operational excellence, system integrity and safety are top priorities • Strategically positioned asset base • Optimize assets and business unit performance • Pursue low risk complementary growth opportunities • Execute on secured growth projects 2
  • 40. U.S. Natural Gas Fundamentals Production and demand forecast to remain robust over the longer term U.S. Lower 48 Production Forecasts Demand Forecast 90 100 80 95 90 70Annual Average Bcf/d Average Annual Bcf/d 85 60 Industrial 80 75 50 70 40 Power 65 30 60 Other 55 20 50 Residential - 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 10 Commercial 0 Enbridge WoodMac CERA EIA 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: EIA Annual Energy Outlook 2013 Early Release Overview 3
  • 41. Demand Growth Driven by Electricity Generation Expected coal plant retirements will boost gas demand Coal Capacity Retirements (GW) 70 60 50 40 30 20 10 0 “Duke Energy anticipates retiring 38 coal and gas-fueled plants, it recently told the North Carolina Utilities Commission. Duke expects to have a 45 percent decline in coal use in 20 years.” (Houston Chronicle 2/20/2013) Retirements Cumulative retirements Source: PIRA Energy Group, October 2012 4
  • 42. U.S. NGL Production Growth Robust NGL production growth ~ mainly from light-end of the barrel 4500 U.S. NGL Production Outlook 4000 Natural Gasoline 3500 Isobutane 3000 Butane 2500 Propane MB/D 2000 1500 1000 Ethane 500 0 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Source: Petral Annual Forecast, August 2012 5
  • 43. Ethane Demand Outlook Ethane supply will outpace cracking capacity before large petrochemical facilities enter service after mid-decadeSource: EnVantage, Outlook for US NGLs, August 2012; reflects high-probability proposed petrochemical expansions. 6
  • 44. Propane Demand Outlook Propane export terminal expansions will provide outlet for growing supply 2013 propane export terminal expansions*: • Enterprise ~ +3.5 MMbbls/month 1Q13 • Targa ~ +1 MMbbls/month 3Q13Source: EnVantage, Outlook for US NGLs, August 2012* Based on Company disclosures. 7
  • 45. Price Forecast Natural Gas Crude to Gas Ratio $5 32 27 $4 22 US$/MMbtu WTI:NG 17 $3 12 7 $2 2 2013 2015 2017 2007 2009 2011 2013 2015 2017 2019 EIA Forecast Forward Curve* Enbridge Forecast Enbridge Forecast * Based on NYMEX NG forward prices as of 2/15/2013. 8
  • 46. Strategy for Growth• Operational excellence, system integrity and safety• Optimize the performance of existing asset base  Expand processing capabilities  Maximize commodity value  Expand asset footprint – proximity to Mississippi Lime, Eaglebine, Cline shale plays  Optimize natural gas segment performance• Pursue low risk growth opportunities  Expand stabilization capacity (fee/demand-based)  Condensate takeaway (fee/demand-based)  Pursue vertical integration (fee/demand-based)• Position Natural Gas business for the future 9
  • 47. Natural Gas Asset Footprint Well positioned portfolio of natural gas assets • Large gathering and processing geographic footprint: • 11,400 miles of gathering & transmission pipelines, 2.2 bcf/day* of active processing capacity, 1.1 bcf/day of treating capacity • Competitively positioned for Granite Wash, Haynesville Shale and emerging shale plays Anadarko Basin EEP G&P Assets Granite Wash Texas Express NGL Pipeline Skellytown Haynesville Shale Fort Worth Basin Barnett Shale East Texas Basin Bossier Sands Mont Belvieu*Includes Ajax natural gas processing plant; in-service mid-2013. 10
  • 48. Strategic Position – Anadarko• Premier asset position in liquids rich Granite Wash shale play TEXAS OKLAHOMA Growth Program: • Growing processing capacity Ajax plant (150 MMcf/d, NGL production ~15kbpd) in-service mid-2013 • Value chain integration: NGL transportation Texas Express NGL pipeline and gathering system (JV with EPD, APC, DPM) 280 kbpd; in-service 3Q13 Texas Express NGL PipelineGathering / Transmission lines 2,900 milesActive processing plants 12 *Processing capacity 1.1 bcf/d **Includes Ajax natural gas processing plant; in-service mid-2013. 11
  • 49. Strategic Position – East Texas • Large geographic footprint • Significant market outlets • Cotton Valley and other rich gas • Highly productive dry gas wells formations Growth Program: • Potential for expansion into the liquids rich Eagle Ford/ Woodbine/ Eaglebine developing shale plays • Expand processing capacity ~ pursue low risk fee-based growth Gathering / Transmission lines 3,900 miles Active treating plants 8 Treating capacity 1.1 bcf/d Active processing plants 5 Processing capacity 0.7 bcf/d 12
  • 50. Strategic Position – North Texas • Stable production • Rich gas drilling and liquids volumes are expected to increase • Substantial footprint in liquids rich northwest region of the Barnett Texas Express Growth Program: NGL Pipeline • Expand reach into oil and associated gas drilling formations – Grow NGL production • Optimize plant capacity through condensate stabilization and expansion Springtown Plant Dallas Gathering / Transmission lines 4,600 miles Active processing plants 9 Processing capacity 0.4 bcf/d 13
  • 51. Logistics Growth • Condensate Logistics • Expand stabilization capacity • Condensate take-away: Pampa, TX rail facility • NGL Logistics • Offer bundled services • Trucking • Natural Gas Logistics • Downstream pathing • Origination 14
  • 52. Enterprise Risk Management & Integrity Investment to be industry leader • 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 15
  • 53. Key Takeaways • Operational excellence, system integrity and safety are top priorities • Strategically positioned asset base • Optimize assets and business unit performance • Pursue low risk complementary growth opportunities • Execute on secured growth projects 16
  • 54. Steve Neyland, VP FinanceFinance
  • 55. Key Messages • Long term value proposition  Attractive yield combined with significant tax deferral  Prudent and sustainable growth  Strong investment grade credit rating • Targeting 2% to 5% annual distribution growth  Distribution growth to be driven by secured projects • Secured Liquids projects collectively further transform the Partnership to lower risk business model • Manageable funding plan and growing financial strength • Strong, strategically aligned, supportive General Partner Enbridge Inc.  Attractive suite of asset drop-down potential by General Partner 2
  • 56. Distribution Growth Target Organic growth platform supports distribution growth 2.7% 4.2% - 3.8% 3.6% 2.1% 2007 2008 2009 2010 2011 2012 2016e 3
  • 57. Disciplined Approach to Growth Investment Criteria Exceed risk-adjusted cost of capital hurdle rate Cash flow accretive to LP unitholder starting in first full year of service Strategic Secured Growth Program Growth focused on low risk Liquids infrastructure Liquids growth projects collectively are transformative to an even lower risk business model Execute growth program Project execution Financial execution 4
  • 58. Capital Forecast (2013-2016)3,000 $ millions Net Capital Forecast (2013 - 2016) ~ $7.4 billion 8,000 Maintenance Maintenance 0.6 capital2,000 Natural Gas 6,000 Other growth and Maintenance 2.0 integrity capital Natural Gas Secured growth capital less 2012 4,000 spend1,000 Liquids 4.8 Liquids 2,000 0 0 2012 2013e 2014e-2016e Average Capital expenditure forecast is net of the Joint Funding Agreements with Enbridge Inc. and included at EEPs base economic interest of 40% (60% funded by Enbridge Inc.). 5
  • 59. Delivering Prudent Growth Attractive suite of organic growth secured ~ solid returns profile Net Capital EEP Target EBITDA ($MM)* In-Service multiple Risk Profile Bakken Growth Projects Bakken Expansion 300 1Q13 7x 10 year ship-or-pay Bakken Rail 145 1Q13 4x 3 year ship-or-pay Bakken Access 100 mid-2013 8x Volume Risk Sandpiper 2,500 early 2016 6xLiquids Eastern Access Sandpiper: 15 year Cost of Service Line 6B Replacement, Line 5, Line 62 expansion 800 2013-2014 9x Eastern Access & Mainline Expansions Line 6B Expansion + tankage 160 early 2016 8x 30 year Cost of Service US Mainline Expansion Line 67 (Border to Superior) Phase 1 3Q14; No volume risk Line 61 (Superior to Flanagan) 760 Phase 2 2015-2016 4x No capital risk** Chicago Connectivity (Line 62 twin) 200 mid-2015 8x Ajax Plant 230 mid-2013 7x Commodity & volume riskGas Texas Express NGL Pipeline 385 3Q13 15 year ship-or-pay $5,580 * Net capital and associated EBITDA for those projects covered by the Joint Funding Agreements included at EEPs base economic interest of 40% (60% funded by Enbridge Inc.). Represents first full-year EBITDA contribution. **Eastern Access has modest capital cost risk. 6
  • 60. Risk Profile – Lower Risk Business Model Crude oil projects progressively transform EEP to lower risk business model 2016e 23% 32% 2012 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, including non-controlling interest. 7
  • 61. Distributable Cash Flow Growth DCF growth underpinned by projects with low risk commercial framework Incremental DCF Eastern Access Eastern Access Bakken Expansions Mainline Expansions Sandpiper Other 2013e 2014e 2015e 2016e Based on forecasted EBITDA contribution from growth projects, less incremental maintenance capital. 8
  • 62. Strengthening Distribution Coverage Secured growth projects improve distribution coverage Transition to high end of 1.25x distribution growth target Long Range Coverage 1.00x TargetCoverage* 0.75x Guidance range 0.50x 0.25x 0.00x 2006 2007 2008 2009 2010 2011 2012 2013(e) 2016(e) * Coverage includes EEQ paid-in-kind distribution. 9
  • 63. Growing Financial Strength Strengthening credit metrics as expansion projects begin to generate cash Debt to EBITDA FFO/Interest 5.05.55.04.5 4.04.03.5 3.03.0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 Target <4.0 times Actuals Target >4.0 times Actuals Will maintain strong investment grade credit profile (BBB/Baa2) 10
  • 64. Joint Funding Agreements Joint funding enhances Partnership’s financing flexibility• Joint funding agreements with Enbridge Inc. apply to 2012-2016 Total Secured Eastern Access & US Mainline Expansion Projects Capital = $8.5 billion• Enbridge Inc. will provide +/- 60% of funding for these projects ~ in form of 100% equity investment• EEP will have separate options to upsize/downsize interest by up to 15% • Bakken Eastern Access & Expansions US Mainline • Provides financing flexibility ~ $720 million over spend period • Natural Gas Expansion Projects $3.7 billion $4.8 billion • EEP ownership range of outcomes = 25% - 55% • Downsize options extended until June 30, 2013 • Upsize options 12 months from last in-service date • Natural drop-down project at later date 100% EEP Funded 40% EEP Funded ~ $3.7 billion ~ $1.9 billion• Special Independent Committee recommendation 11
  • 65. Liquidity Position Strong liquidity position enhances financing flexibility 12/31/2012 Credit Facilities Cash 3,000  $3.1 billion 425* Committed Credit Facilities 2,500  $1.5 billion 2,000 Commercial Paper Program $ millions 425* 1,500 $3,100 228 2,675 1,000 $1,511 1,283 500 0 Available Liquidity Credit Facilities* Increased credit facilities of $425 million in February 2013. 12
  • 66. Financing Plan Manageable financing plan Financing Plan Available Maturity Windows• 50/50 Debt to Equity funding target• Joint funding with ENB enhances 600 EEP’s financing flexibility• Maintain investment grade credit 500 rating & strong liquidity 400 Financing Options $Millions Debt 300  Bank Credit Facility  Term Debt 200  Hybrid Security Equity 100  EEP Common Unit Offering  EEQ Common Share Offering 0  Private Placement 2013 2015 2017 2019 2021 2023 2025 2027 2029 2031 2033 2035 2037 2039 2041 2043  Hybrid Security OLP Senior Notes MLP Senior Notes MLP Junior Notes 13
  • 67. De-risking the Business Through DisciplinedHedging Program Business Mix (before hedging)* NGL and Crude Price Fluctuations Prices: -20% Prices: +20% 2013 ~1.5% of 2013 EBITDA guidance Fee Based Commodity 80% Exposure 2014 20% After hedging 2015 -$60 -$40 -$20 $0 $20 $40 $60 Business Mix (after hedging)* Natural Gas Price Fluctuations Prices: -20% Prices: +20% 2013 Commodity 5% ~0.1% of 2013 EBITDA guidance Fee Based 2014 80% Hedged 15% 2015 -$60 -$40 -$20 $0 $20 $40 $60 Note: amounts in $ millions based on 2013 estimates – takes into*Based on forecasted 2013 gross margin. account hedges in place as of 12/31/2012. 14
  • 68. Enterprise Risk Management & Integrity Investment to be Industry Leader $400 Liquids Integrity Capital* Liquids Integrity Capital Expenditures: $300  Sleeving pipeline segment  Cut-out & replace pipeline segment$ million  Coating pipeline segment $200 Recoverability:  Engage shipper group annually to $100 recover integrity capital through toll structure $0 2008 2009 2010 2011 2012 2013e 2014e 2015e 2016e * Integrity capital expenditures do not include Line 6B replacement. New or modified requirements could impact our future integrity costs. 15
  • 69. Financial Outlook 2013 Earnings Outlook 2013 Business Mix 1,400 1,350 Guidance Range 1,200 1,250 20% Liquids 80% Natural Gas 1,000 940 800 860 $ millions Based on forecasted 2013 operating income. 600 Growing EBITDA 410 400 390 200 $ millions 1,000 0 Adjusted EBITDA* Adjusted Depreciation** Operating Income*Adjusted EBITDA inclusive of non-controlling interest and other income. EBITDA from non-controlling interest estimated at $160 million, which is inclusive of ~$35 million of other income 500associated with AEDC. 2010 2011 2012 2013e**Depreciation includes non-controlling interest component of ~$35 million. Based on adjusted EBITDA. 16
  • 70. Key Messages • Long term value proposition  Attractive yield combined with significant tax deferral  Prudent and sustainable growth  Strong investment grade credit rating • Distribution growth: targeting 2% to 5% annual growth • Secured Liquids projects collectively further transform the Partnership to lower risk business model • Execute on growth program: project execution & financial execution • Manageable funding plan and growing financial strength • Maintain strong investment grade credit rating • Strong, strategically aligned, supportive General Partner Enbridge Inc.  Visible growth and attractive long-term outlook 17
  • 71. Appendix 18
  • 72. Financial Metrics LT Financial Metrics 2009 2010* 2011* 2012* Target Debt to EBITDA 4.2x 4.3x 3.9x 4.9x <4.0x Debt to Capitalization 48% 50% 48% 50% 50% FFO/Debt (%) 17% 17% 19% 14% >20% FFO/Interest 3.8x 4.0x 3.8x 3.2x >4.0x Distribution Coverage 1.11 1.14 1.01 0.79 1.05-1.10 * Normalized for 6A and 6B remediation costs and insurance recoveries 19
  • 73. Mark Maki, PresidentClosing Remarks
  • 74. Key Takeaways • System integrity, safety and project execution are top priorities • Secured Liquids projects collectively further transform the Partnership to lower risk business model • Execute on growth program: project execution and financial execution • Distribution growth: targeting 2% to 5% annual growth • Growth trajectory in Liquids business will bolster distribution growth • Visible growth and attractive long-term outlook • Maintaining investment grade credit rating is a priority 2