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Enbridge Energy Partners Investment Community Presentation May 2013

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Page 1: Eep may13 pres

Enbridge Energy Partners

Investment Community Presentation May 2013

Page 2: Eep may13 pres

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

Page 3: Eep may13 pres

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

Page 4: Eep may13 pres

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

Page 5: Eep may13 pres

Investment Proposition

5

Page 6: Eep may13 pres

Attractive Investment Proposition

* As of May 15, 2013

** Return CAGR since inception (nominal)

Nu

sta

r

EE

P

En

erg

y T

ran

sfe

r

Bo

ard

wa

lk

Will

iam

s

Bu

cke

ye

Kin

de

r M

org

an

On

eo

k

En

terp

rise

Pla

ins A

ll A

me

rica

n

Ma

ge

llan

Mid

str

ea

m

Su

no

co

Lo

gis

tics

S&

P 5

00 U

tilit

ies

FT

SE

NA

RIE

T

S&

P 5

00

10-Y

r T

rea

su

ry N

ote

s

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

Page 7: Eep may13 pres

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

Page 8: Eep may13 pres

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

Page 9: Eep may13 pres

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

Page 10: Eep may13 pres

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

Page 11: Eep may13 pres

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

Page 12: Eep may13 pres

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 2020Oil Sands Conventional HeavyConv. 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

Page 13: Eep may13 pres

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)

Page 14: Eep may13 pres

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

LLS Maya

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

Page 15: Eep may13 pres

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

Page 16: Eep may13 pres

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

Page 17: Eep may13 pres

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

Page 18: Eep may13 pres

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

Page 19: Eep may13 pres

Western U.S. Gulf Coast Access

Cushing

Houston

Chicago/ Flanagan

Port Arthur

1

3

2 Enbridge 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

Page 20: Eep may13 pres

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

Page 21: Eep may13 pres

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.

Page 22: Eep may13 pres

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

Pro

c C

apac

ity

(Mm

cf/d

)

NG

L P

rod

uct

ion

(K

bp

d)

NGL & Gas Processing Capacity

*Includes Elk City acquisition

Premier position in liquids rich natural gas producing basin

Page 23: Eep may13 pres

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

Page 24: Eep may13 pres

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

Page 25: Eep may13 pres

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

Page 26: Eep may13 pres

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

Page 27: Eep may13 pres

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

Page 28: Eep may13 pres

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

Page 29: Eep may13 pres

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

Page 30: Eep may13 pres

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

Co

vera

ge*

* Coverage includes EEQ paid-in-kind distribution.

Page 31: Eep may13 pres

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

Page 32: Eep may13 pres

Supplemental Slides

Page 33: Eep may13 pres

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* AdjustedOperating Income

Depreciation**

$ m

illio

ns

Guidance Range

33

500

1,000

2010 2011 2012 2013e

$ m

illio

ns

Growing EBITDA

Based on adjusted EBITDA.

80%

20% Liquids

Natural Gas

Business Mix

Based on forecasted 2013 operating income.

Page 34: Eep may13 pres

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.

Liq

uid

s

Gas

Page 35: Eep may13 pres

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

Page 36: Eep may13 pres

Priority One - Focus on Operations

5.9

10.7

4.6

Enbridge Rest of Industry

Bar

rels

sp

illed

per

bill

ion

bar

rel-

mile

s

Volume Spilled *

10.5

Including Marshall

Excluding Marshall

Industry Average Enbridge

0.005

0.021

Nu

mb

er

pe

r b

illio

n b

arre

l-m

iles

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

Page 37: Eep may13 pres

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

Page 38: Eep may13 pres

Impacts of Lines 6A & 6B Incidents

Life-to-Date as of

12/31/12Booked 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

Page 39: Eep may13 pres

Crude Oil Storage Capacity

0

5

10

15

20

25

2010 2011 2012 2013

Cap

acit

y (m

illio

n b

bls

)

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

Page 40: Eep may13 pres

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

Page 41: Eep may13 pres

Major Canadian and US Crude Oil Pipelines and Refineries

41

Page 42: Eep may13 pres

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.

Page 43: Eep may13 pres

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

Eq

uit

y L

en

gth

Fra

c S

pre

ad

Total Hedged Cash Flows (Balance of Year)

Volume

Physical Hedged

Page 44: Eep may13 pres

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