This presentation provides an overview of Enbridge Energy Partners and its investment proposition. EEP has an attractive yield of 7.1% and total shareholder return of 11% over 10 years. It owns strategic energy infrastructure assets including large pipeline systems transporting crude oil and natural gas across North America. EEP has a secured capital program of over $8 billion to expand these systems and connect growing supply regions to new markets, supported by long-term commercial agreements.

1. Enbridge Energy Partners
Investment Community Presentation
May 2013

2. 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 and subsequently filed Quarterly
Reports on Form 10-Q, 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

3. Corporate Structure
Ownership 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 Partner
Interest
And
16.9%
Limited Partner
Interest
100% Indirectly Owned
100%
Voting Shares
13.5%
Listed Shares
Management
and Control
16.6% Limited Partner
Interest (I Units)
86.5%
64.6%
Enbridge Energy
Company, Inc.
Enbridge Energy
Partners, L.P.
(NYSE: EEP)
Enbridge Energy
Management, L.L.C.
(NYSE: EEQ)
Enbridge Inc.
(NYSE: ENB)
Public
Public
Enbridge Inc. owns
~21% of EEP
ENB*
• Yield: 2.6%
• 10-yr TSR: 19%
• EV: $66B
EEQ*
• Yield: 7.1%
• 10-yr TSR: 15%
• EV: $1.6B
EEP*
• Yield: 7.1%
• 10-yr TSR: 11%
• EV: $14B
3

4. Enbridge Energy Partners Factsheet
4
Financial Highlights
Market Cap* $9.4B
Yield* 7.1%
Distribution $2.17/unit annual
Total Shareholder Return (10yr) 11%
Credit Rating Investment Grade
BBB/Baa2
2013 EBIDTA Guidance (Adjusted) $1,250MM-$1,350MM
EEP is one of the longest serving MLPs (since 1991) and has consistently delivered
cash distributions to its unitholders
Key Assets
Liquids Deliveries of ~ 2.2 MMbpd
Transportation Pipelines 6,265 miles of pipe
Gathering Pipelines 240 miles of pipe
Storage Capacity 39.4 million barrels
Natural Gas Deliveries of ~ 2.5 bcf/d
Gathering and Transportation Pipelines 11,400 miles of pipe
Processing 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 from
Western Canada into the U.S.
 Largest pipeline transporter of crude oil from
the Bakken formation
 Over $8 billion of organic growth secured
 Cash flows secured predominantly by long-term,
low risk commercial structures

5. Investment Proposition
5

6. Attractive Investment Proposition
* As of May 15, 2013
** Return CAGR since inception (nominal)
Nustar
EEP
EnergyTransfer
Boardwalk
Williams
Buckeye
KinderMorgan
Oneok
Enterprise
PlainsAllAmerican
MagellanMidstream
SunocoLogistics
S&P500Utilities
FTSENARIET
S&P500
10-YrTreasuryNotes
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
10%
Peer average: 5.8%
EEP: 7.1%
MLPs*
Other Asset
Classes*
Attractive Yield • One of the longest serving pipeline MLPs (1991)
• Attractive return CAGR
• Track record of consistently delivering cash
distributions
• Prudent growth
$0
$20,000
$40,000
$60,000
$80,000
$100,000
$120,000
$140,000
$160,000
$180,000
Total Shareholder Return
1991 2012
6

7. Distribution Growth Target
Organic growth platform supports distribution growth
2007 2008 2009 2010 2011 2012 2016e
2.7% 4.2% - 3.8% 3.6% 2.1%
7

8. 65%62%
19%
 ~$37 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
Strength of GP – Enbridge Inc.
8

9. 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
EEP Liquids Pipelines
ENB Liquids Pipelines and Joint Ventures
EEP Natural Gas Pipelines
EEP NGL Pipeline Joint Venture
9
North Dakota System
Midcontinent System
Lakehead System

10. Dominant Transporter of Canadian Crude Oil to the US
Edmonton
Fort McMurray
Chicago
Trans Mountain
8%
Express
6%
W Corridor
4%
Alberta Oil sands
Hardisty
Keystone
21%
US Imports 20121
MMbpd
Western Canada
Enbridge
Others
2.4
1.3
1.1
Saudi Arabia 1.4
Mexico 1.0
Venezuela 0.9
Iraq 0.5
Nigeria 0.4
Colombia 0.4
Kuwait 0.3
Angola 0.2
Brazil 0.2
Other2 1.0
Total 8.7
2012 Capacity MMbpd
Enbridge 2.50
Keystone 0.59
Trans Mountain 0.30
Express 0.28
West Corridor 0.15
Enbridge transports 53%
of U.S. bound Western
Canadian production
ENB ~ 15% Total US Imports
1 Average 2012. Source: Enbridge, Energy Information Administration
10

11. Potential North American Crude Oil Supply Balance
Canadian
Canadian
Canadian
U.S.
U.S.
U.S.
Foreign
Foreign
Foreign
0
2
4
6
8
10
12
14
16
18
2010 2015 2020
High Shale Forecast
High Shale Forecast
Source: Enbridge Internal Forecast
Domestic production growth provides opportunity to displace foreign
sourced crude oil
North American Demand by Supply Source
MMbpd
 North American Supply
 U.S. Consumption
 Transportation Bottlenecks
 Enbridge Market Access
(pipeline connectivity)
11

12. Enbridge System – Supply Push, Demand Pull
Markets
 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 Coast
0.0
1.0
2.0
3.0
4.0
5.0
2012 2013 2014 2015 2016 2017 2018 2019 2020
Oil Sands Conventional Heavy
Conv. Light and Medium Pentanes/Condensate
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2012 2013 2014 2015 2016 2017 2018 2019 2020
Source: CAPP – Crude Oil Forecast, Markets & Pipelines (June 2012)
Forecast Western Canada Production
Forecast Bakken Production
1.5 MMbpd
0.5 MMbpd
Matching Domestic Crude Oil Supply Growth to Market Demand
Enbridge &
EEP Mainline
System
12

13. Commodity Price Fundamentals Driving
Market Access Strategy
$108
$104
$98
Alberta Light
Bakken
Brent
Maya
Asia
$89
$105
LLS
WCS
$91
$76
$95
Light Crude
Heavy Crude
$101
WTI
Light Differentials
Brent – WTI $9
LLS – WTI $10
Asia – WTI $13
WTI – Bakken $4
WTI - Alberta
Light
$6
Heavy Differentials
Maya – WCS $22
Asia – WCS $25
13
Significant Infrastructure Investment Opportunities
May 15, 2013 prices (in US$/bbl)

14. Timely Access to Premium Crude Oil Markets
14
Montreal
Gretna
Regina
Hardisty
Kerrobert
Toledo
Buffalo
Edmonton
Fort
McMurray
Cromer
Cushing
Patoka
Clearbrook
Port Arthur
Sarnia
Houston St. James
Chicago/
Flanagan
Brent
LLS
LLSMaya
Brent
2014
+600 kbpd
2014
+300 kbpd
2015
+300 kbpd
2015
+440 kbpd
2013
+80 kbpd
~ 1.7MMbpd of new market access will significantly alleviate market price dislocations

15. Montreal
Toronto
Gretna
Regina
Hardisty
Kerrobert
Superior
Toledo
Buffalo
Edmonton
Houston
Detroit
Clearbrook
Flanagan
Fort McMurray
Cromer
Cushing
Patoka
Chicago
Wood
River
Sarnia
Enbridge Inc.
Enbridge Energy Partners L.P.
Strategic Position Crude Oil Transportation
15
Competitive Advantages:
• Scale: 2.5 million bpd
• Connected to rapidly growing
supply sources
• Market diversity
• Access to premium markets
• Well positioned for extension to
new markets
• Established ROW
• Multiple lines: quality/reliability

16. Linking North American Crude Supply Growth
to Refining Centers
Cushing
Houston
Chicago/
Flanagan
Port
Arthur
1
3
2
Enbridge Energy Partners Projects (EEP) ~ $7.3B*
Sandpiper Pipeline Project ($2.5B)
• +225/375 kbpd early 2016
US Mainline Expansions ($2.4B):
Line 67 Expansion (border to Superior)
• +350 kbpd, total 800 kbpd; 3Q14 to 2015
Line 61 Expansion (Superior to Flanagan)
• +800 kbpd, total 1,200 kbpd; 3Q14 to 2016
Chicago Connectivity
• +570 kbpd Line 62 twin; 2H 2015
Eastern Access Expansions ($2.4B):
Line 5 Expansion
• +50 kbpd 2Q13
Line 62 Spearhead North Expansion
• +105 kbpd 4Q13
Line 6B Replacement
• +260 kbpd late 2013/early 2014; +70 kbpd early 2016
 Eastern Access & US Mainline Expansions
EEP/ENB joint funded
*represents total capital before joint funding
3
1
2
3
16
Montreal
Superior
Canadian/U.S. East
Coast Refinery Markets
U.S. Gulf Coast
Refinery Markets
Sarnia
EEP North Dakota System
Patoka
Enbridge (ENB) & Enbridge Partners (EEP)
Market Access Programs
 U.S. Gulf Coast Access
 Eastern Access
 Light Oil Market Access
4
5
4
5
6
5
1
2
4
6
6
U.S. Mid-West
Refinery Markets
Enbridge Inc. Projects (ENB)
Seaway Pipeline - ENB and EPD JV
• +400 kbpd 1Q13
Flanagan South Pipeline
• +585 kbpd (36” line) mid-2014
Seaway Pipeline Twin & Lateral
• ENB and EPD JV; +450k bpd 1H 2014
Toledo Pipeline Partial Twin
• +80 kbpd 2013
Line 9 Reversal & Expansion
• +240 kbpd late 2013, 2014;+80 kbpd 2014
Southern Access Extension
• +300 kbpd 2015
Trunkline JV
• +440 to 660 kbpd 2015
1
Growth Projects:
 Commercially secured
 Low-risk framework
 Long-term contracts
5 2
3
4
5
6
7
Memphis
St. James
7

17. Bakken Expansion – Sandpiper Pipeline
17
Clearbrook
Gretna
Saskatchewan
Enbridge Mainline System
North Dakota System
Bakken Expansion Project
Saskatchewan System (ENF)
Bakken Access Program
Sandpiper Pipeline
Minot
Lignite
Weyburn
Cromer
Berthold
Steelman
Tioga
Stanley
Alliance Pipeline
Regional 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 Superior
Regional Rail Takeaway & Delivery
• Bakken Berthold Rail +80 kbpd (1Q13)
• Philadelphia Rail JV + 80 kbpd (4Q13)
Regional Gathering
• Bakken Access +100 kbpd (2Q13)
Berthold Rail Program
EEP pipeline takeaway will reach 580 kbpd with next phase of expansion
Capital = $3.0B
Growth Projects:
 Commercial support
 Low-risk framework
 Long-term contracts
to Superior

18. Eastern Access Growth Projects
Clearbrook
Superior
Sarnia
Chicago
Patoka
Toledo
Montreal
Westover
3
1
4
5
Cushing
EEP/ENB joint funded
ENB
EEP 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 tankage
EEP US Mainline Expansion Project ($0.5B)
Chicago Connectivity - Spearhead North Twin (2H 2015)
• +570 bpd capacity increase into Chicago
 EEP/ENB joint funded
1
2
2
3
5
Flanagan
Linking North American crude supply growth to eastern refining centers
Growth Projects:
 Commercially secured
 Low-risk framework
 Long-term contracts
Refining center
2
Enbridge 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 expansion
4
5
18

19. Western U.S. Gulf Coast Access
Cushing
Houston
Chicago/
Flanagan
Port Arthur
1
3
2Enbridge Inc. Projects ($5.2B)
Seaway Pipeline
• Enbridge Inc. and Enterprise JV
• current capacity up to 400 kbpd
Flanagan South Pipeline
• Initial capacity 585 kbpd (36” line)
• 100% ENB; in-service mid-2014
Seaway Pipeline Twin & Lateral
• Enbridge Inc. and Enterprise JV
• Initial capacity 450k bpd; 30’’ line
• In-service 1H 2014
1
2
3
EEP US Mainline Expansion ($1.9B)
Line 67 Expansion
• +350 kbpd capacity increase to 800 kbpd
• expanded to full hydraulic capacity
Line 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 required
5
4 4
5
19
Growth Projects:
 Commercially secured
 Low-risk framework
 Long-term contracts
Refining center
Linking North American crude supply growth to USGC refining centers
Heavy
43%Light
57%
Western USGC Refining
Processing Capability
Source: EIA and Enbridge’s internal estimates
W USGC ~ 4,400 kbpd

20. Eastern U.S. Gulf Coast Access - Trunkline JV
Superior
Reversed
Trunkline
Exxon Mobil (Baton Rouge) 503
Marathon (Garyville) 490
Valero (Norco) 250
ConocoPhillips (Belle Chase) 247
Motiva (Convent) 227
Motive (Norco) 220
Chalmette 189
Valero (Meraux) 135
Alon USA (Krotz Springs) 83
Placid (Pt Allen) 56
Shell (St. Rose) 55
Memphis
Flanagan
Chevron (Pascagoula) 330
Shell (Saraland) 85
Hunt (Tuscaloosa) 72
Gulf Atlantic (Mobile) 20
Southern
Access
Extension
E USGC ~ 3,200 kbpd
Source: EIA and Enbridge’s internal estimates
Mississippi River Refinery Capacity
Alabama / Mississippi Refinery Capacity
20
Patoka
St. James

21. Natural Gas Asset Footprint
21
Anadarko Basin
Granite Wash
Fort Worth Basin
Barnett Shale
Haynesville Shale
East Texas Basin
Bossier Sands
EEP G&P Assets
Texas Express NGL
Pipeline
Skellytown
Mont Belvieu
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
*Includes Ajax natural gas processing plant; in-service 3Q13.

22. Anadarko System
• Strong fundamentals and growth in
the Granite Wash
• Increasing NGL recovery capability
22
Granite Wash
Economics of high GPM gas
Natural Gas
NGLs
Well
Condensate
$-
$2.00
$4.00
$6.00
$8.00
$10.00
$12.00
$14.00
Natural Gas NGLs Well Condensate
~ $9.97 / Mcf
Assumes $4 Nymex; $94 WTI
0
200
400
600
800
1,000
1,200
0
20
40
60
80
100
120
2009 2010* 2011 2012 2013e
ProcCapacity(Mmcf/d)
NGLProduction(Kbpd)
NGL & Gas Processing Capacity
*Includes Elk City acquisition
Premier position in liquids rich natural gas producing basin

23. Texas Express NGL Pipeline
Natural Gas midstream vertical integration
• Texas Express NGL Pipeline
– 20” natural gas liquid pipeline,
580 miles
– 280k bpd capacity, expandable
to 400k bpd
– JV with Enterprise (35%),
Anadarko (20%) and DCP
Midstream (10%)
– $1.1B (EEP 35%)
– 15 year Ship-or-Pay
agreements
– In-service 3Q 2013
• Strategic Benefits
– Addresses NGL constraints
– Enhances competitive position
– Enhances customer netback
– Integrates fractionation
23
Hobbs

24. G&P Growth Update – Expand ETX Processing
Capacity
24
Project 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 region
Expand 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. Operational Excellence & Project Execution
Industry
Leadership
Integrity
Management
Leak Detection
Capability and
Control Systems
Third Party Damage
Avoidance and
Detection
Incident Response
Capacity
Employee and
Contractor
Occupational Safety
Public Safety and
Environmental
Protection
Organizational commitment to being “best in class”
Operational
Excellence
Project
Execution
Project
Development
Proven track record: on-time & on-budget
Supply Chain
Management
Construction
Experience
Life Cycle
Gating Control
Regulatory &
Permitting
Major
Projects
25

26. Business Mix & Risk Profile
*Note: based on 2013 forecast
Liquids
Pipelines
80%
Natural
Gas
20%
Operating Income*
0%
20%
40%
60%
80%
100%
2008 2009 2010 2011 2012 2013 2014 2015 2016
60%
12%
18%
59%
23%
28%
Commodity
Fee-Based
Cost of Service /
Take-or-Pay
Crude oil projects progressively transform EEP to lower risk business model
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.
26

27. Delivering Low-Risk Sustainable Growth
27
Note:
Eastern Access and Mainline Expansion liquids expansion projects are jointly funded by EEP & ENB.
Commercial Structure
- Commodity/Volume Sensitive- Take-or-Pay- Cost of Service
Expected Project In-Service Period 1H13 2H13 1H14 2H14 1H15 2H15 1H16
Liquids Projects
Bakken Pipeline Expansion
Bakken Rail
Bakken Access
Eastern Access: Line 6B repl., Line 5, Line 62 exp.
Mainline Expansion: Line 61 and 67 Exp. Phase 1
Mainline Expansion: Line 61 and 67 Exp. Phase 2
Mainline Expansion: Line 62 Twin (Chicago Connectivity)
Sandpiper
Eastern Access: Line 6B exp. and Tankage
Natural Gas Projects
Ajax Plant - Granite Wash
Texas Express NGL Pipeline JV
Beckville Plant - Cotton Valley

28. Capital Forecast (2013-2016)
28
Net Capital Forecast (2013 - 2016)
Executing on Financing Plan
 Recent funding actions ~
$2.2 billion
 Enhanced liquidity
 Supportive General Partner
Capital expenditures are net of the Joint Funding Agreements with Enbridge Inc. and included at EEP's base economic interest of 40% (60%
funded by Enbridge Inc.).
Strong investment grade
credit profile (BBB/Baa2)
Liquids
Liquids
Natural Gas
Natural Gas
Maintenance
Maintenance
0
1,000
2,000
3,000
2012 2013e 2014e-2016e Average
$ millions

29. Financing Plan
1,611
0
500
1,000
1,500
2,000
Available Liquidity 3/31/2013
Credit Facilities Cash
$1,852
$ millions
29
 $3.1 billion Committed Credit
Facilities
 $1.9 billion Available Liquidity
Financing Options
Debt
 Bank Credit Facility
 Term Debt
 Hybrid Security
Equity
 EEP Common Unit Offering
 EEQ Common Share Offering
 Private Placement
 Hybrid Security
Liquidity Position
Recent Actions
 $273 million EEQ offering
 Issued $1.2 billion preferred units
 Expect to exercise Joint Funding option
~$700 million
242
Executing on our financing plan

30. 30
Strengthening Distribution Coverage
Secured growth projects improve distribution coverage
0.00x
0.25x
0.50x
0.75x
1.00x
1.25x
2006 2007 2008 2009 2010 2011 2012 2013(e) 2016(e)
Long Range
Coverage
Target
Guidance range
Transition to high end of
distribution growth target
Coverage*
* Coverage includes EEQ paid-in-kind distribution.

31. Key Takeaways
• Operational excellence, system integrity, safety and project
execution are top priorities
• Supportive General Partner
• Strong liquids fundamentals and system utilization support pipeline
expansion projects
• Liquids growth projects collectively transform the Partnership to
lower risk business model
• Growth trajectory in Liquids business will bolster distribution growth
• Maintaining investment grade credit rating is a priority
31

32. Supplemental Slides

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 income
associated with AEDC.
**Depreciation includes non-controlling interest component of ~$35 million.
Earnings Outlook 2013
1,250
860
390
1,350
940
410
0
200
400
600
800
1,000
1,200
1,400
Adjusted EBITDA* Adjusted
Operating Income
Depreciation**
$millions
Guidance Range
33
500
1,000
2010 2011 2012 2013e
$millions
Growing EBITDA
Based on adjusted EBITDA.
80%
20%
Liquids
Natural Gas
Business Mix
Based on forecasted 2013 operating income.

34. Delivering Prudent Growth
34
* 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.
Net Capital
EEP
($MM)*
Target
In-Service
EBITDA
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 2Q13 8x Volume Risk
Sandpiper 2,500 early 2016 6x
Sandpiper:
15 year Cost of Service
Eastern Access & Mainline Expansions
30 year Cost of Service
No volume risk
No capital risk**
Eastern Access
Line 6B Replacement, Line 5,
Line 62 expansion 800 1H 2013 - early 2014 9x
Line 6B Expansion + tankage 160 early 2016 8x
US Mainline Expansion
Line 67 (Border to Superior)
Line 61 (Superior to Flanagan) 760
Phase 1 3Q14;
Phase 2 2015-2016 4x
Chicago Connectivity (Line 62 twin) 200 2H 2015 8x
Ajax Plant 230 3Q13 7x Commodity & volume risk
Texas Express NGL Pipeline 385 3Q13 15 year ship-or-pay
$5,580
Attractive suite of organic growth secured ~ solid returns profile
**Eastern Access has modest capital cost risk.
LiquidsGas

35. Joint Funding Agreements
35
2012-2016 Total Secured
Capital = $8.5 billion
• Bakken
Expansions
• Natural Gas
$3.7 billion
Eastern Access &
US Mainline
Expansion Projects
$4.8 billion
100% EEP Funded
~ $3.7 billion
40% EEP Funded
~ $1.9 billion
• Joint funding agreements with Enbridge Inc. apply to
Eastern Access & US Mainline Expansion Projects
• Enbridge Inc. will provide +/- 60% of funding for these
projects ~ in form of 100% equity investment
• EEP will have separate options to downsize/upsize
interest 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 recommendation
Joint funding enhances Partnership’s financing flexibility

36. Priority One - Focus on Operations
5.9
10.7
4.6
Enbridge Rest of Industry
Barrelsspilledperbillionbarrel-miles
Volume Spilled *
10.5
Including
Marshall
Excluding
Marshall
Industry AverageEnbridge
0.005
0.021
Numberperbillionbarrel-miles
Frequency 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 incidents
36
Enbridge Pipeline Safety Track Record

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
37

38. Impacts of Lines 6A & 6B Incidents
Life-to-Date as of
12/31/12
Booked in Q1 2013
Total
Estimated Cost
Total Costs $868 $175** $1,043
Lost Revenues $16 $0 $16
Gross Impact $884 $175 $1,059
Less: Insurance Recoveries $505 $0 $505
Estimated 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 additional
recovery efforts.
38

39. Crude Oil Storage Capacity
0
5
10
15
20
25
2010 2011 2012 2013
Capacity(millionbbls)
Growing Cushing Storage Capacity
New planned storage capacity
39
Contract Tankage
• One of the largest storage
owner/operators at Cushing
• Long term fee based contracts
̶ Staggered maturities
̶ Creditworthy customers
̶ Capital recovery over initial
term
Operational Tankage
• Manage overall system flexibility
̶ Return on investment
included in tolls

40. Regulatory Framework
System Regulatory Methodology
Lakehead System
Base 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 throughput
subject 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 Allowance
Alberta Clipper • Cost of Service at NEB basic** + 2.25% + Tax Allowance
Facilities Surcharge
Mechanism (FSM)
• Cost of Service: 55% equity, 45% debt rate base + Tax Allowance
North Dakota • Toll indexed to PPI + 2.65% (Fall back is cost of service*)
• Phase V-VI Expansion Cost of Service over 5-7 years
Mid-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 Return
PPI + 2.65% = 8.6% effective July 2012
40

41. Major Canadian and US Crude Oil Pipelines and Refineries
41

42. De-risking the Business Through Disciplined
Hedging Program
42
NGL and Crude Price Fluctuations
Note: amounts in $ millions based on 2013 estimates – takes into
account hedges in place as of 12/31/2012.
-$60 -$40 -$20 $0 $20 $40 $60
2015
2014
2013
Prices: -20% Prices: +20%
-$60 -$40 -$20 $0 $20 $40 $60
2015
2014
2013
Prices: -20% Prices: +20%
Natural Gas Price Fluctuations
~1.5% of 2013 EBITDA guidance
~0.1% of 2013 EBITDA guidance
Fee Based
80%
Commodity
Exposure
20%
Fee Based
80% Hedged
15%
Commodity 5%
Business Mix (before hedging)*
Business Mix (after hedging)*
After hedging
*Based on forecasted 2013 gross margin.

43. Estimated Commodity Positions Apr-Dec 2013
43
Unaudited, $ in millions.
* Options valued at their strike prices to determine hedged cash flows.
Hedge Price Value
% $ MM
Net Equity Gas 61,903 MMbtu/d 49% 30,481 MMbtu/d $4.80 /MMbtu $40.2
C2 3,519 bpd 41% 1,435 bpd $0.62 /gallon $10.2
C3 2,447 bpd 86% 2,095 bpd $1.05 /gallon $25.3
iC4 471 bpd 57% 267 bpd $1.59 /gallon $4.9
C4 867 bpd 59% 512 bpd $1.54 /gallon $9.1
C5 1,024 bpd 78% 802 bpd $1.83 /gallon $16.9
Total NGLs 8,328 bpd 61% 5,111 bpd $66.4
Condensate 1,464 bpd 100% 1,464 bpd $90.13/barrel $36.3
Total Equity Length 9,792 6,575 $142.9
C2 3,434 bpd 0% 0 bpd $0.00 /gallon $0.0
C3 3,065 bpd 57% 1,750 bpd $0.93 /gallon $18.7
iC4 816 bpd 57% 462 bpd $1.64 /gallon $8.8
C4 1,096 bpd 65% 715 bpd $1.53 /gallon $12.6
C5 414 bpd 98% 406 bpd $1.98 /gallon $9.3
Total NGLs 8,825 bpd 38% 3,333 bpd $0.97 /gallon $49.4
Shrink & Fuel (34,842) MMbtu/d 41% (14,250) MMbtu/d $3.85 /MMbtu ($15.1)
Total Frac Spread $34.3
Condensate 1,788 bpd 85% 1,513 bpd $85.92/barrel $35.8
Shrink (8,936) MMbtu/d 72% (6,432) MMbtu/d $5.49 /MMbtu ($9.7)
Condensate Frac $26.1
$203.3
EquityLengthFracSpread
Total Hedged Cash Flows (Balance of Year)
Volume
Physical Hedged

44. Tax Considerations
EEQ EEP
Allocated Taxable Income
Mutual Fund Limitations
Unrelated Business Income Tax
Schedule K-1
Form 1099 *
State Filing Obligations
* Form 1099 issued for tax year during which shares are disposed.
44