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Eep may13 pres

  1. 1. Enbridge Energy PartnersInvestment Community PresentationMay 2013
  2. 2. Legal NoticeThis presentation includes certain forward looking information (“FLI”) to provide Enbridge Energy Partners, L.P. (“EEP”) andEnbridge Energy Management, L.L.C. (“EEQ”) investors and potential investors with information about EEP and EEQ andmanagement’s assessment of the future plans and operations, which may not be appropriate for other purposes. FLIinvolves 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 webelieve that such forward looking statements are reasonable based on currently available information, such statementsinvolve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or eventsand future results of operations may differ materially from those expressed in these forward-looking statements. Many ofthe factors that will determine these results are beyond Enbridge Partners’ ability to control or predict. Specific factors thatcould cause actual results to differ from those in the forward-looking statements include: (1) changes in the demand for orthe supply of, forecast data for and price trends related to crude oil, liquid petroleum, natural gas and NGLs, including therate of development of the Alberta Oil Sands; (2) Enbridge Partners’ ability to successfully complete and finance expansionprojects; (3) the effects of competition, in particular, by other pipeline systems; (4) shut-downs or cutbacks at facilities ofEnbridge Partners or refineries, petrochemical plants, utilities or other businesses for which Enbridge Partners transportsproducts or to whom Enbridge Partners sells products; (5) hazards and operating risks that may not be covered fully byinsurance; (6) changes in or challenges to Enbridge Partners’ tariff rates; and (7) changes in laws or regulations to whichEnbridge Partners is subject, including compliance with environmental and operational safety regulations that may increasecosts of system integrity testing and maintenance.Our FLI is subject to risks and uncertainties pertaining to operating performance, regulatory parameters, project approvaland support, weather, economic conditions, interest rates and commodity prices, including but not limited to thosediscussed more extensively in our filings with U.S. securities regulators. The impact of any one risk, uncertainty or factor onany particular FLI is not determinable with certainty as these are interdependent and our future course of action depends onmanagement’s assessment of all information available at the relevant time. Except to the extent required by law, weassume no obligation to publicly update or revise any FLI, whether as a result of new information, future events orotherwise. All FLI in this presentation is expressly qualified in its entirety by these cautionary statements. You are referred toEEP’s and EEQ’s SEC filings, including its most recently filed Annual Report on Form 10-K and subsequently filed QuarterlyReports on Form 10-Q, for a more detailed discussion of risk factors. This presentation makes reference to certain financialmeasures, such as adjusted net income, which are not recognized under generally accepted accounting principles, referredto as GAAP.2
  3. 3. Corporate StructureOwnership as of May 15, 2013.*yield as of May 15, 2013; EV as of 4/30/13; and TSR (nominal CAGR) as of 12/31/12.2%General PartnerInterestAnd16.9%Limited PartnerInterest100% Indirectly Owned100%Voting Shares13.5%Listed SharesManagementand Control16.6% Limited PartnerInterest (I Units)86.5%64.6%Enbridge EnergyCompany, Inc.Enbridge EnergyPartners, L.P.(NYSE: EEP)Enbridge EnergyManagement, L.L.C.(NYSE: EEQ)Enbridge Inc.(NYSE: ENB)PublicPublicEnbridge Inc. owns~21% of EEPENB*• Yield: 2.6%• 10-yr TSR: 19%• EV: $66BEEQ*• Yield: 7.1%• 10-yr TSR: 15%• EV: $1.6BEEP*• Yield: 7.1%• 10-yr TSR: 11%• EV: $14B3
  4. 4. Enbridge Energy Partners Factsheet4Financial HighlightsMarket Cap* $9.4BYield* 7.1%Distribution $2.17/unit annualTotal Shareholder Return (10yr) 11%Credit Rating Investment GradeBBB/Baa22013 EBIDTA Guidance (Adjusted) $1,250MM-$1,350MMEEP is one of the longest serving MLPs (since 1991) and has consistently deliveredcash distributions to its unitholdersKey AssetsLiquids Deliveries of ~ 2.2 MMbpdTransportation Pipelines 6,265 miles of pipeGathering Pipelines 240 miles of pipeStorage Capacity 39.4 million barrelsNatural Gas Deliveries of ~ 2.5 bcf/dGathering and Transportation Pipelines 11,400 miles of pipeProcessing Capacity (26 active plants**) 2,165MMcf/d**Treating capacity (8 active plants) 1,090 MMcf/d*As of April 30, 2013. **Includes Ajax natural gas processing plant; in-service 3Q13.Highlights Strategically positioned assets: Largest pipeline transporter of crude oil fromWestern Canada into the U.S. Largest pipeline transporter of crude oil fromthe Bakken formation Over $8 billion of organic growth secured Cash flows secured predominantly by long-term,low risk commercial structures
  5. 5. Investment Proposition5
  6. 6. Attractive Investment Proposition* As of May 15, 2013** Return CAGR since inception (nominal)NustarEEPEnergyTransferBoardwalkWilliamsBuckeyeKinderMorganOneokEnterprisePlainsAllAmericanMagellanMidstreamSunocoLogisticsS&P500UtilitiesFTSENARIETS&P50010-YrTreasuryNotes0%1%2%3%4%5%6%7%8%9%10%Peer average: 5.8%EEP: 7.1%MLPs*Other AssetClasses*Attractive Yield • One of the longest serving pipeline MLPs (1991)• Attractive return CAGR• Track record of consistently delivering cashdistributions• Prudent growth$0$20,000$40,000$60,000$80,000$100,000$120,000$140,000$160,000$180,000Total Shareholder Return1991 20126
  7. 7. Distribution Growth TargetOrganic growth platform supports distribution growth2007 2008 2009 2010 2011 2012 2016e2.7% 4.2% - 3.8% 3.6% 2.1%7
  8. 8. 65%62%19% ~$37 billion equity market cap Strong investment grade Proven track record: industryleading EPS and DPS growth• 5 year EPS CAGR of 13%• 5 year DPS CAGR of 13% Strategy aligned with Partnership Joint funding providesPartnership financing flexibilityStrength of GP – Enbridge Inc.8
  9. 9. 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/dayEEP Liquids PipelinesENB Liquids Pipelines and Joint VenturesEEP Natural Gas PipelinesEEP NGL Pipeline Joint Venture9North Dakota SystemMidcontinent SystemLakehead System
  10. 10. Dominant Transporter of Canadian Crude Oil to the USEdmontonFort McMurrayChicagoTrans Mountain8%Express6%W Corridor4%Alberta Oil sandsHardistyKeystone21%US Imports 20121MMbpdWestern CanadaEnbridgeOthers2.41.31.1Saudi Arabia 1.4Mexico 1.0Venezuela 0.9Iraq 0.5Nigeria 0.4Colombia 0.4Kuwait 0.3Angola 0.2Brazil 0.2Other2 1.0Total 8.72012 Capacity MMbpdEnbridge 2.50Keystone 0.59Trans Mountain 0.30Express 0.28West Corridor 0.15Enbridge transports 53%of U.S. bound WesternCanadian productionENB ~ 15% Total US Imports1 Average 2012. Source: Enbridge, Energy Information Administration10
  11. 11. Potential North American Crude Oil Supply BalanceCanadianCanadianCanadianU.S.U.S.U.S.ForeignForeignForeign0246810121416182010 2015 2020High Shale ForecastHigh Shale ForecastSource: Enbridge Internal ForecastDomestic production growth provides opportunity to displace foreignsourced crude oilNorth American Demand by Supply SourceMMbpd North American Supply U.S. Consumption Transportation Bottlenecks Enbridge Market Access(pipeline connectivity)11
  12. 12. Enbridge System – Supply Push, Demand PullMarkets Canada• Western Canada• Ontario• Quebec PADD I PADD II• Minneapolis• Chicago Area• Toledo• Detroit• Cushing PADD III• Houston• Port Arthur Strategic Growth• Eastern PADD II• PADD I• Eastern USGC• West Coast0. 2013 2014 2015 2016 2017 2018 2019 2020Oil Sands Conventional HeavyConv. Light and Medium Pentanes/Condensate0. 2013 2014 2015 2016 2017 2018 2019 2020Source: CAPP – Crude Oil Forecast, Markets & Pipelines (June 2012)Forecast Western Canada ProductionForecast Bakken Production1.5 MMbpd0.5 MMbpdMatching Domestic Crude Oil Supply Growth to Market DemandEnbridge &EEP MainlineSystem12
  13. 13. Commodity Price Fundamentals DrivingMarket Access Strategy$108$104$98Alberta LightBakkenBrentMayaAsia$89$105LLSWCS$91$76$95Light CrudeHeavy Crude$101WTILight DifferentialsBrent – WTI $9LLS – WTI $10Asia – WTI $13WTI – Bakken $4WTI - AlbertaLight$6Heavy DifferentialsMaya – WCS $22Asia – WCS $2513Significant Infrastructure Investment OpportunitiesMay 15, 2013 prices (in US$/bbl)
  14. 14. Timely Access to Premium Crude Oil Markets14MontrealGretnaReginaHardistyKerrobertToledoBuffaloEdmontonFortMcMurrayCromerCushingPatokaClearbrookPort ArthurSarniaHouston St. JamesChicago/FlanaganBrentLLSLLSMayaBrent2014+600 kbpd2014+300 kbpd2015+300 kbpd2015+440 kbpd2013+80 kbpd~ 1.7MMbpd of new market access will significantly alleviate market price dislocations
  15. 15. MontrealTorontoGretnaReginaHardistyKerrobertSuperiorToledoBuffaloEdmontonHoustonDetroitClearbrookFlanaganFort McMurrayCromerCushingPatokaChicagoWoodRiverSarniaEnbridge Inc.Enbridge Energy Partners L.P.Strategic Position Crude Oil Transportation15Competitive Advantages:• Scale: 2.5 million bpd• Connected to rapidly growingsupply sources• Market diversity• Access to premium markets• Well positioned for extension tonew markets• Established ROW• Multiple lines: quality/reliability
  16. 16. Linking North American Crude Supply Growthto Refining CentersCushingHoustonChicago/FlanaganPortArthur132Enbridge Energy Partners Projects (EEP) ~ $7.3B*Sandpiper Pipeline Project ($2.5B)• +225/375 kbpd early 2016US Mainline Expansions ($2.4B):Line 67 Expansion (border to Superior)• +350 kbpd, total 800 kbpd; 3Q14 to 2015Line 61 Expansion (Superior to Flanagan)• +800 kbpd, total 1,200 kbpd; 3Q14 to 2016Chicago Connectivity• +570 kbpd Line 62 twin; 2H 2015Eastern Access Expansions ($2.4B):Line 5 Expansion• +50 kbpd 2Q13Line 62 Spearhead North Expansion• +105 kbpd 4Q13Line 6B Replacement• +260 kbpd late 2013/early 2014; +70 kbpd early 2016 Eastern Access & US Mainline ExpansionsEEP/ENB joint funded*represents total capital before joint funding312316MontrealSuperiorCanadian/U.S. EastCoast Refinery MarketsU.S. Gulf CoastRefinery MarketsSarniaEEP North Dakota SystemPatokaEnbridge (ENB) & Enbridge Partners (EEP)Market Access Programs U.S. Gulf Coast Access Eastern Access Light Oil Market Access45456512466U.S. Mid-WestRefinery MarketsEnbridge Inc. Projects (ENB)Seaway Pipeline - ENB and EPD JV• +400 kbpd 1Q13Flanagan South Pipeline• +585 kbpd (36” line) mid-2014Seaway Pipeline Twin & Lateral• ENB and EPD JV; +450k bpd 1H 2014Toledo Pipeline Partial Twin• +80 kbpd 2013Line 9 Reversal & Expansion• +240 kbpd late 2013, 2014;+80 kbpd 2014Southern Access Extension• +300 kbpd 2015Trunkline JV• +440 to 660 kbpd 20151Growth Projects: Commercially secured Low-risk framework Long-term contracts5 234567MemphisSt. James7
  17. 17. Bakken Expansion – Sandpiper Pipeline17ClearbrookGretnaSaskatchewanEnbridge Mainline SystemNorth Dakota SystemBakken Expansion ProjectSaskatchewan System (ENF)Bakken Access ProgramSandpiper PipelineMinotLigniteWeyburnCromerBertholdSteelmanTiogaStanleyAlliance PipelineRegional Pipeline Takeaway:• EEP North Dakota Pipeline Capacity• 235 kbpd current• Bakken Expansion +120 kbpd (1Q13)• Sandpiper Project (2016)• + 225 kbpd to Clearbrook• + 375 kbpd Clearbrook to SuperiorRegional Rail Takeaway & Delivery• Bakken Berthold Rail +80 kbpd (1Q13)• Philadelphia Rail JV + 80 kbpd (4Q13)Regional Gathering• Bakken Access +100 kbpd (2Q13)Berthold Rail ProgramEEP pipeline takeaway will reach 580 kbpd with next phase of expansionCapital = $3.0BGrowth Projects: Commercial support Low-risk framework Long-term contractsto Superior
  18. 18. Eastern Access Growth ProjectsClearbrookSuperiorSarniaChicagoPatokaToledoMontrealWestover3145CushingEEP/ENB joint fundedENBEEP Eastern Access Projects ($2.4B)Line 5 Expansion (2Q13)• +50 kbpd capacity increase into Sarnia (540 kbpd total)Spearhead North Expansion (4Q13)• +105 kbpd capacity increase into Chicago (235 kbpd total)Line 6B Replacement & Expansion (2014 to early 2016)• +260 kbpd capacity expansion into Sarnia (500 kbpd total)• +70 kbpd capacity expansion Griffith to Stockbridge• Breakout tankageEEP US Mainline Expansion Project ($0.5B)Chicago Connectivity - Spearhead North Twin (2H 2015)• +570 bpd capacity increase into Chicago EEP/ENB joint funded12235FlanaganLinking North American crude supply growth to eastern refining centersGrowth Projects: Commercially secured Low-risk framework Long-term contractsRefining center2Enbridge Inc. Expansions ($0.6B)Toledo Pipeline Partial Twin (2013)• +100 kbpd access to Michigan & Ohio refineries (180 kbpd)Line 9 Reversal (2013/2014)• 240 kbpd reversal to access refineries in Ontario & Quebec• 80 kbpd expansion4518
  19. 19. Western U.S. Gulf Coast AccessCushingHoustonChicago/FlanaganPort Arthur132Enbridge Inc. Projects ($5.2B)Seaway Pipeline• Enbridge Inc. and Enterprise JV• current capacity up to 400 kbpdFlanagan South Pipeline• Initial capacity 585 kbpd (36” line)• 100% ENB; in-service mid-2014Seaway Pipeline Twin & Lateral• Enbridge Inc. and Enterprise JV• Initial capacity 450k bpd; 30’’ line• In-service 1H 2014123EEP US Mainline Expansion ($1.9B)Line 67 Expansion• +350 kbpd capacity increase to 800 kbpd• expanded to full hydraulic capacityLine 61 Expansion• +800 kbpd capacity increase to 1,200 kbpd• expanded to full hydraulic capacity Phase 1 3Q14; Phase 2 2015-2016 EEP/ENB joint funded No pipe construction required54 4519Growth Projects: Commercially secured Low-risk framework Long-term contractsRefining centerLinking North American crude supply growth to USGC refining centersHeavy43%Light57%Western USGC RefiningProcessing CapabilitySource: EIA and Enbridge’s internal estimatesW USGC ~ 4,400 kbpd
  20. 20. Eastern U.S. Gulf Coast Access - Trunkline JVSuperiorReversedTrunklineExxon Mobil (Baton Rouge) 503Marathon (Garyville) 490Valero (Norco) 250ConocoPhillips (Belle Chase) 247Motiva (Convent) 227Motive (Norco) 220Chalmette 189Valero (Meraux) 135Alon USA (Krotz Springs) 83Placid (Pt Allen) 56Shell (St. Rose) 55MemphisFlanaganChevron (Pascagoula) 330Shell (Saraland) 85Hunt (Tuscaloosa) 72Gulf Atlantic (Mobile) 20SouthernAccessExtensionE USGC ~ 3,200 kbpdSource: EIA and Enbridge’s internal estimatesMississippi River Refinery CapacityAlabama / Mississippi Refinery Capacity20PatokaSt. James
  21. 21. Natural Gas Asset Footprint21Anadarko BasinGranite WashFort Worth BasinBarnett ShaleHaynesville ShaleEast Texas BasinBossier SandsEEP G&P AssetsTexas Express NGLPipelineSkellytownMont BelvieuWell positioned portfolio of natural gas assets• Large gathering and processing geographic footprint:• 11,400 miles of gathering & transmission pipelines, 2.2 bcf/day* of activeprocessing capacity, 1.1 bcf/day of treating capacity• Competitively positioned for Granite Wash, Haynesville Shale and emerging shale plays*Includes Ajax natural gas processing plant; in-service 3Q13.
  22. 22. Anadarko System• Strong fundamentals and growth inthe Granite Wash• Increasing NGL recovery capability22Granite WashEconomics of high GPM gasNatural GasNGLsWellCondensate$-$2.00$4.00$6.00$8.00$10.00$12.00$14.00Natural Gas NGLs Well Condensate~ $9.97 / McfAssumes $4 Nymex; $94 WTI02004006008001,0001,2000204060801001202009 2010* 2011 2012 2013eProcCapacity(Mmcf/d)NGLProduction(Kbpd)NGL & Gas Processing Capacity*Includes Elk City acquisitionPremier position in liquids rich natural gas producing basin
  23. 23. Texas Express NGL PipelineNatural Gas midstream vertical integration• Texas Express NGL Pipeline– 20” natural gas liquid pipeline,580 miles– 280k bpd capacity, expandableto 400k bpd– JV with Enterprise (35%),Anadarko (20%) and DCPMidstream (10%)– $1.1B (EEP 35%)– 15 year Ship-or-Payagreements– In-service 3Q 2013• Strategic Benefits– Addresses NGL constraints– Enhances competitive position– Enhances customer netback– Integrates fractionation23Hobbs
  24. 24. G&P Growth Update – Expand ETX ProcessingCapacity24Project Overview• Construction of 150 MMcf/d cryogenic natural gas processing plant – Beckville Plant (Panola county) Will expand EEP’s processing capacity in ETX Cotton Valley/Haynesville region to 820 MMcf/d Capital investment ~$140 million; in-service early 2015 Cotton Valley liquids rich producing basin ~2.5-3.0 GPM gas Combination of fee + commodity based contracts with acreage dedication Active large-scale producers in the regionExpand G&P Strategic Asset Footprint Consistent with EEP strategy to optimize existing infrastructure Competitive advantage due to extensive gathering footprint Incremental NGL volumes will enhance EEP’s downstream integration strategy Potential for additional investment opportunities
  25. 25. Operational Excellence & Project ExecutionIndustryLeadershipIntegrityManagementLeak DetectionCapability andControl SystemsThird Party DamageAvoidance andDetectionIncident ResponseCapacityEmployee andContractorOccupational SafetyPublic Safety andEnvironmentalProtectionOrganizational commitment to being “best in class”OperationalExcellenceProjectExecutionProjectDevelopmentProven track record: on-time & on-budgetSupply ChainManagementConstructionExperienceLife CycleGating ControlRegulatory &PermittingMajorProjects25
  26. 26. Business Mix & Risk Profile*Note: based on 2013 forecastLiquidsPipelines80%NaturalGas20%Operating Income*0%20%40%60%80%100%2008 2009 2010 2011 2012 2013 2014 2015 201660%12%18%59%23%28%CommodityFee-BasedCost of Service /Take-or-PayCrude oil projects progressively transform EEP to lower risk business modelCost 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.26
  27. 27. Delivering Low-Risk Sustainable Growth27Note:Eastern Access and Mainline Expansion liquids expansion projects are jointly funded by EEP & ENB.Commercial Structure- Commodity/Volume Sensitive- Take-or-Pay- Cost of ServiceExpected Project In-Service Period 1H13 2H13 1H14 2H14 1H15 2H15 1H16Liquids ProjectsBakken Pipeline ExpansionBakken RailBakken AccessEastern Access: Line 6B repl., Line 5, Line 62 exp.Mainline Expansion: Line 61 and 67 Exp. Phase 1Mainline Expansion: Line 61 and 67 Exp. Phase 2Mainline Expansion: Line 62 Twin (Chicago Connectivity)SandpiperEastern Access: Line 6B exp. and TankageNatural Gas ProjectsAjax Plant - Granite WashTexas Express NGL Pipeline JVBeckville Plant - Cotton Valley
  28. 28. Capital Forecast (2013-2016)28Net Capital Forecast (2013 - 2016)Executing on Financing Plan Recent funding actions ~$2.2 billion Enhanced liquidity Supportive General PartnerCapital expenditures are net of the Joint Funding Agreements with Enbridge Inc. and included at EEPs base economic interest of 40% (60%funded by Enbridge Inc.).Strong investment gradecredit profile (BBB/Baa2)LiquidsLiquidsNatural GasNatural GasMaintenanceMaintenance01,0002,0003,0002012 2013e 2014e-2016e Average$ millions
  29. 29. Financing Plan1,61105001,0001,5002,000Available Liquidity 3/31/2013Credit Facilities Cash$1,852$ millions29 $3.1 billion Committed CreditFacilities $1.9 billion Available LiquidityFinancing OptionsDebt Bank Credit Facility Term Debt Hybrid SecurityEquity EEP Common Unit Offering EEQ Common Share Offering Private Placement Hybrid SecurityLiquidity PositionRecent Actions $273 million EEQ offering Issued $1.2 billion preferred units Expect to exercise Joint Funding option~$700 million242Executing on our financing plan
  30. 30. 30Strengthening Distribution CoverageSecured growth projects improve distribution coverage0.00x0.25x0.50x0.75x1.00x1.25x2006 2007 2008 2009 2010 2011 2012 2013(e) 2016(e)Long RangeCoverageTargetGuidance rangeTransition to high end ofdistribution growth targetCoverage** Coverage includes EEQ paid-in-kind distribution.
  31. 31. Key Takeaways• Operational excellence, system integrity, safety and projectexecution are top priorities• Supportive General Partner• Strong liquids fundamentals and system utilization support pipelineexpansion projects• Liquids growth projects collectively transform the Partnership tolower risk business model• Growth trajectory in Liquids business will bolster distribution growth• Maintaining investment grade credit rating is a priority31
  32. 32. Supplemental Slides
  33. 33. Financial Outlook 2013*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 incomeassociated with AEDC.**Depreciation includes non-controlling interest component of ~$35 million.Earnings Outlook 20131,2508603901,35094041002004006008001,0001,2001,400Adjusted EBITDA* AdjustedOperating IncomeDepreciation**$millionsGuidance Range335001,0002010 2011 2012 2013e$millionsGrowing EBITDABased on adjusted EBITDA.80%20%LiquidsNatural GasBusiness MixBased on forecasted 2013 operating income.
  34. 34. Delivering Prudent Growth34* Net capital and associated EBITDA for those projects covered by the Joint Funding Agreements included at EEPs base economic interest of 40% (60% funded byEnbridge Inc.). Represents first full-year EBITDA contribution.Net CapitalEEP($MM)*TargetIn-ServiceEBITDAmultiple Risk ProfileBakken Growth ProjectsBakken Expansion 300 1Q13 7x 10 year ship-or-payBakken Rail 145 1Q13 4x 3 year ship-or-payBakken Access 100 2Q13 8x Volume RiskSandpiper 2,500 early 2016 6xSandpiper:15 year Cost of ServiceEastern Access & Mainline Expansions30 year Cost of ServiceNo volume riskNo capital risk**Eastern AccessLine 6B Replacement, Line 5,Line 62 expansion 800 1H 2013 - early 2014 9xLine 6B Expansion + tankage 160 early 2016 8xUS Mainline ExpansionLine 67 (Border to Superior)Line 61 (Superior to Flanagan) 760Phase 1 3Q14;Phase 2 2015-2016 4xChicago Connectivity (Line 62 twin) 200 2H 2015 8xAjax Plant 230 3Q13 7x Commodity & volume riskTexas Express NGL Pipeline 385 3Q13 15 year ship-or-pay$5,580Attractive suite of organic growth secured ~ solid returns profile**Eastern Access has modest capital cost risk.LiquidsGas
  35. 35. Joint Funding Agreements352012-2016 Total SecuredCapital = $8.5 billion• BakkenExpansions• Natural Gas$3.7 billionEastern Access &US MainlineExpansion Projects$4.8 billion100% EEP Funded~ $3.7 billion40% EEP Funded~ $1.9 billion• Joint funding agreements with Enbridge Inc. apply toEastern Access & US Mainline Expansion Projects• Enbridge Inc. will provide +/- 60% of funding for theseprojects ~ in form of 100% equity investment• EEP will have separate options to downsize/upsizeinterest by up to 15%• EEP expects to downsize interest to 25%• financing flexibility ~ $720 million over spend period• Upsize options 12 months from last in-service date• Natural drop-down project at later date• Special Independent Committee recommendationJoint funding enhances Partnership’s financing flexibility
  36. 36. Priority One - Focus on Operations5.910.74.6Enbridge Rest of IndustryBarrelsspilledperbillionbarrel-milesVolume Spilled *10.5IncludingMarshallExcludingMarshallIndustry AverageEnbridge0.0050.021Numberperbillionbarrel-milesFrequency of Spills *Enbridge Industry Average* Based on mandatory reports to PHMSA of accidents and infrastructure, 2002-2011.• 12 billion barrels delivered since 2002 - 99.9996% successful delivery rate• 2011 spill volume frequency was lowest on record• Still not good enough – target is zero incidents36Enbridge Pipeline Safety Track Record
  37. 37. Enterprise Risk Management & Integrity• Inline inspection (ILI) 16,000 km inspected in 2011/2012More than 4,000 pipe joints examinedMedical 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 geotechnicalconditions, corrosion control, 3rd party activity• Non-destructive testing Targeted investigation sites• Equipment checks Seals, sumps, rotating equipment37
  38. 38. Impacts of Lines 6A & 6B IncidentsLife-to-Date as of12/31/12Booked in Q1 2013TotalEstimated CostTotal Costs $868 $175** $1,043Lost Revenues $16 $0 $16Gross Impact $884 $175 $1,059Less: Insurance Recoveries $505 $0 $505Estimated Costs, Lost Revenues and Gross Impact(excluding fines/penalties)**Except for the $3.7 million civil penalty assessed by the PHMSA (Pipeline and Hazardous Materials Safety Administration) during the second quarter of 2012,w hich is included in total cost estimate.Unaudited amounts, $ in millions. Represents life-to-date amounts pursuant to impact of Lines 6A & 6B incidents.**Reflects additional cost estimate in response to the Order issued by the U.S. EPA (Environmental Protection Agency) on March 14, 2013 requiring additionalrecovery efforts.38
  39. 39. Crude Oil Storage Capacity05101520252010 2011 2012 2013Capacity(millionbbls)Growing Cushing Storage CapacityNew planned storage capacity39Contract Tankage• One of the largest storageowner/operators at Cushing• Long term fee based contracts̶ Staggered maturities̶ Creditworthy customers̶ Capital recovery over initialtermOperational Tankage• Manage overall system flexibility̶ Return on investmentincluded in tolls
  40. 40. Regulatory FrameworkSystem Regulatory MethodologyLakehead SystemBase toll • Toll indexed to PPI +2.65% (Fallback is cost of service)SEP II • Negotiated Cost of Service – ROE at NEB base** +/-3% depending on throughputsubject to 7.5% - 15% limits.• Currently at 11.6%Terrace • Flat surcharge (currently at C$.01/bbl)Southern Access • Cost of Service at 9% + Tax AllowanceAlberta Clipper • Cost of Service at NEB basic** + 2.25% + Tax AllowanceFacilities SurchargeMechanism (FSM)• Cost of Service: 55% equity, 45% debt rate base + Tax AllowanceNorth Dakota • Toll indexed to PPI + 2.65% (Fall back is cost of service*)• Phase V-VI Expansion Cost of Service over 5-7 yearsMid-Continent • Toll indexed to PPI + 2.65% (Fall back is cost of service*)• Contract-based for storage* Can revert to Cost of Service tolling governed by the FERC by demonstrating substantial divergence between costs and rates.** NEB base is the annually published NEB Multi-Pipeline rate of ReturnPPI + 2.65% = 8.6% effective July 201240
  41. 41. Major Canadian and US Crude Oil Pipelines and Refineries41
  42. 42. De-risking the Business Through DisciplinedHedging Program42NGL and Crude Price FluctuationsNote: amounts in $ millions based on 2013 estimates – takes intoaccount hedges in place as of 12/31/2012.-$60 -$40 -$20 $0 $20 $40 $60201520142013Prices: -20% Prices: +20%-$60 -$40 -$20 $0 $20 $40 $60201520142013Prices: -20% Prices: +20%Natural Gas Price Fluctuations~1.5% of 2013 EBITDA guidance~0.1% of 2013 EBITDA guidanceFee Based80%CommodityExposure20%Fee Based80% Hedged15%Commodity 5%Business Mix (before hedging)*Business Mix (after hedging)*After hedging*Based on forecasted 2013 gross margin.
  43. 43. Estimated Commodity Positions Apr-Dec 201343Unaudited, $ in millions.* Options valued at their strike prices to determine hedged cash flows.Hedge Price Value% $ MMNet Equity Gas 61,903 MMbtu/d 49% 30,481 MMbtu/d $4.80 /MMbtu $40.2C2 3,519 bpd 41% 1,435 bpd $0.62 /gallon $10.2C3 2,447 bpd 86% 2,095 bpd $1.05 /gallon $25.3iC4 471 bpd 57% 267 bpd $1.59 /gallon $4.9C4 867 bpd 59% 512 bpd $1.54 /gallon $9.1C5 1,024 bpd 78% 802 bpd $1.83 /gallon $16.9Total NGLs 8,328 bpd 61% 5,111 bpd $66.4Condensate 1,464 bpd 100% 1,464 bpd $90.13/barrel $36.3Total Equity Length 9,792 6,575 $142.9C2 3,434 bpd 0% 0 bpd $0.00 /gallon $0.0C3 3,065 bpd 57% 1,750 bpd $0.93 /gallon $18.7iC4 816 bpd 57% 462 bpd $1.64 /gallon $8.8C4 1,096 bpd 65% 715 bpd $1.53 /gallon $12.6C5 414 bpd 98% 406 bpd $1.98 /gallon $9.3Total NGLs 8,825 bpd 38% 3,333 bpd $0.97 /gallon $49.4Shrink & Fuel (34,842) MMbtu/d 41% (14,250) MMbtu/d $3.85 /MMbtu ($15.1)Total Frac Spread $34.3Condensate 1,788 bpd 85% 1,513 bpd $85.92/barrel $35.8Shrink (8,936) MMbtu/d 72% (6,432) MMbtu/d $5.49 /MMbtu ($9.7)Condensate Frac $26.1$203.3EquityLengthFracSpreadTotal Hedged Cash Flows (Balance of Year)VolumePhysical Hedged
  44. 44. Tax ConsiderationsEEQ EEPAllocated Taxable IncomeMutual Fund LimitationsUnrelated Business Income TaxSchedule K-1Form 1099 *State Filing Obligations* Form 1099 issued for tax year during which shares are disposed.44