The document is an agenda for an investor presentation. It outlines the schedule, including presentations on strategic overview, liquids pipelines, natural gas, and finance. Breakfast and lunch will be served. The president of Enbridge Energy Partners, Mark Maki, will give remarks to close the event.
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Eep2013 investordaypresentation
1.
2. Agenda
8:30 - 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 Finance
9:05 - 9:30 am Strategic Overview Steve Neyland
VP Finance,
President Mark Maki,
Enbridge Energy Partners
Enbridge Energy Partners
11:55 - 12:00 pm Closing Remarks
9:30 - 10:40 am Liquids Pipelines
President, Mark Maki,
Stephen Wuori, President,
Enbridge Energy Partners
Liquids Pipelines,
Enbridge Inc.
12:00 - 1:00 pm Lunch
10:40 - 10:55 am Break Olmstead Room
Enbridge Energy Partners, L.P.
Enbridge Energy Management, L.L.C.
4. 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
6. 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
7. 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
9. 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
10. Attractive Investment Proposition
Attractive Yield • One of the longest serving pipeline MLPs (1991)
• Attractive return CAGR
10% • 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
11. Strategic Position
Premier 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
12. 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
13. 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
14. 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
15. Business Mix & Risk Profile
Crude 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
17. 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 &
Permitting
Organizational commitment to being “best in class” Proven track record: on-time & on-budget
13
18. 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
21. 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
22. 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 markets
Seattle 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
23. 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
24. North American Demand by Supply Source
20
15 Foreign
Foreign
High Shale Forecast
Foreign
High Shale Forecast
MMbpd
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
25. Commodity Price Fundamentals Driving
Market 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
$105
North American Supply North American Demand Transportation Bottlenecks
Significant Infrastructure Investment Opportunities
February 20, 2013 prices (in US$/bbl)
6
26. Western US Gulf Coast Access
1
Chicago/
Flanagan
2
1 Associated Mainline Expansion
• In-service = Various (2014 – 2015)
Cushing
2 Flanagan South Pipeline
• In-service = mid 2014, +585 kbpd 3 Western USGC Refining
Processing Capability
3 Seaway Pipeline Acquisition & Reversal 4
• In-service = May 2012, +400 kbpd
Heavy
4 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
28. Eastern Access
Hardisty
Regina
Gretna
Montreal
Clearbrook
Superior
1
Westover
1 Line 5 Expansion Sarnia
• In-service = early 2013, +50 kbpd Chicago Toledo
5
2 3
Spearhead North Expansion Flanagan
• In-service = early 2014, +105 kbpd 2
3 Line 6B Replacement
• In-service = early 2014, +260 kbpd
4 Line 9 Reversal
• In-service = mid 2013 / mid 2014, +240 kbpd
5 Toledo Pipeline Partial Twin
• In-service = early 2013, +80 kbpd Cushing
9
29. Light Oil Market Access
Hardisty
1
Gretna
Montreal
Clearbrook
2
1 Canadian Mainline Terminal Capability
Superior
• In-service = mid 2015/early 2016
2 Sandpiper Project
• In-service = early 2016, +225/375 kbpd Sarnia
3 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 Patoka
4 Eastern Access Upsize
a) Line 6B Expansion
• In-service = early 2016, +70 kbpd
b) Line 9 Reversal Expansion Cushing
• In-service = mid 2014, +80 kbpd
5 Southern Access Extension
• In-service = early 2015, +300 kbpd
10
30. 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
31. Matching North American Crude Supply Growth
to Refining Centers
Growth 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 Markets
Enbridge Energy Partners Projects (EEP) ~ $7.3B* 6 Flanagan
Sandpiper Pipeline Project ($2.5B) Patoka
1 • +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 Cushing
3 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 JV
5 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-2014
4 Line 5 Expansion 3 Seaway Pipeline Twin & Lateral
• +50 kbpd early 2013 Port • ENB and EPD JV; +450k bpd mid-2014
5 Line 62 (Spearhead North) Expansion Arthur 4 Toledo Pipeline Partial Twin
• +105 kbpd early 2014 • +80 kbpd 2013
6 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
32. 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
33. 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
34. 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 • $24+ B of projects under
• Advanced cost & schedule controls
• Proactive risk management
management
• ELT & Board of Directors oversight
• ~1,150 FTE’s
Construction
• Industry-leading safety record
• Deep field experience
• Robust quality control of materials & construction
15
35. Major Projects Execution Status Update
Demonstrated track-record: on-time and on-budget execution
Expected
Cost Schedule
Projects Cost In-service Date
Indicator Indicator
($ 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
36. 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
37. 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
39. 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
42. 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
43. 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 70
Annual 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
44. 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
45. 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
46. Ethane Demand Outlook
Ethane supply will outpace cracking capacity before large
petrochemical facilities enter service after mid-decade
Source: EnVantage, Outlook for US NGLs, August 2012; reflects high-probability proposed petrochemical expansions.
6
47. 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 3Q13
Source: EnVantage, Outlook for US NGLs, August 2012
* Based on Company disclosures.
7
48. 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
49. 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
50. 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
51. 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 Pipeline
Gathering / Transmission lines 2,900 miles
Active processing plants 12 *
Processing capacity 1.1 bcf/d *
*Includes Ajax natural gas processing plant; in-service mid-2013.
11
52. 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
53. 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
55. 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
56. 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
59. 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
61. 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
62. Capital Forecast (2013-2016)
3,000 $ millions
Net Capital Forecast (2013 - 2016)
~ $7.4 billion
8,000
Maintenance Maintenance
0.6
capital
2,000
Natural Gas
6,000 Other growth and
Maintenance 2.0 integrity capital
Natural Gas Secured growth
capital less 2012
4,000 spend
1,000
Liquids
4.8
Liquids 2,000
0
0
2012 2013e 2014e-2016e Average
Capital expenditure forecast is net of the Joint Funding Agreements with Enbridge Inc. and included at EEP's base economic interest of 40%
(60% funded by Enbridge Inc.).
5
63. Delivering Prudent Growth
Attractive suite of organic growth secured ~ solid returns profile
Net Capital
EEP Target EBITDA
($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 6x
Liquids
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 risk
Gas
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 EEP's base economic interest of 40% (60% funded by
Enbridge Inc.). Represents first full-year EBITDA contribution.
**Eastern Access has modest capital cost risk.
6
64. 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
65. 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
66. Strengthening Distribution Coverage
Secured growth projects improve distribution coverage
Transition to high end of
1.25x distribution growth target
Long Range
Coverage
1.00x Target
Coverage*
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
67. Growing Financial Strength
Strengthening credit metrics as expansion projects begin to generate cash
Debt to EBITDA FFO/Interest
5.0
5.5
5.0
4.5
4.0
4.0
3.5
3.0
3.0 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
68. 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
69. 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
70. 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
71. De-risking the Business Through Disciplined
Hedging 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
72. 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
73. 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 500
associated with AEDC. 2010 2011 2012 2013e
**Depreciation includes non-controlling interest component of ~$35 million. Based on adjusted EBITDA.
16
74. 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
79. 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
