Legal Notice

2

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 EEP’s 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) EEP’s 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 EEP or refineries, petrochemical plants, utilities or other businesses

for which EEP transports products or to whom EEP sells products; (5) hazards and operating risks that may not be covered fully by

insurance, including those related to Line 6B and any additional fines and penalties assessed in connection with the crude oil release on

that line; (6) changes in or challenges to EEP’s tariff rates; and (7) changes in laws or regulations to which EEP is subject, including

compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance.

FLI regarding “drop-down” sales opportunities for our ownership in Midcoast Operating, L.P. are further qualified by the fact that Midcoast

Energy Partners, L.P. is under no obligation to buy any of our interests in Midcoast Operating, L.P., and we are under no obligation to sell

any such additional interests. As a result, we do not know when or if any such additional interests will be sold.

Our FLI is also 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. Any FLI in this presentation is based only on information currently available to us and speaks only of the

date on which it is made. 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 and by such other factors as discussed in 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.

Corporate Structure

*Ownership, as of February 14, 2014.

Yield as of February 26, 2014; EV and TSR (nominal CAGR) as of 12/31/13.

2%

General Partner

Interest

And

16.3%

Limited Partner

Interest

100% Indirectly Owned

100% Voting Shares 11.7% Listed Shares

Management

and Control

19.5% Limited Partner

Interest (I Units)

88.3%

62.2%

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: 3.0%

• 10-yr TSR: 17%

• EV: $66B

EEQ*

• Yield: 8.1%

• 10-yr TSR: 12%

• EV: $1.8B

EEP*

• Yield: 7.8%

• 10-yr TSR: 9%

• EV: $14.1B

3

Midcoast Energy

Partners, L.P. (NYSE: MEP)

Midcoast

Operating, L.P.

61%

Limited Partner

Interest

38.999% LP interest;

0.001% GP interest

46.0% Public

52% LP interest;

2% GP interest

MEP*

• Yield: 6.1%

Enbridge Energy Partners Factsheet

Financial Highlights

Market Cap* $11B

Yield* 7.8%

Distribution $2.17/unit annual

Total Shareholder Return (10yr CAGR) 9%

Credit Rating Investment Grade BBB/Baa2

2014 Adjusted EBITDA Guidance** $1.5 to $1.6 Billion

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 plants) 2.3 Bcf/d

Treating Capacity (11 plants) 1.3 Bcf/d

*As of February 26,2014. ** Includes non-controlling interest estimated at $355 million.

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 $8.5 billion of organic growth secured

Cash flows secured predominantly by long-term, low risk commercial structures

4

Investment Proposition

5

Attractive Investment Proposition

* As February 26, 2014

** Return CAGR since inception (nominal)

Nusta

r

EE

P

Kin

der

Morg

an

Will

iam

s

Energ

y T

ransfe

r

Buckeye

Oneok

Pla

ins A

ll A

merican

Spectr

a P

art

ners

Ente

rprise

Magella

n M

idstr

eam

Sunoco L

ogis

tics

Bo

ard

wa

lk

FT

SE

NA

RE

IT

S&

P 5

00

Utilit

ies

10-Y

r T

reasury N

ote

s

S&

P 5

00

0%

1%

2%

3%

4%

5%

6%

7%

8%

9%

10%

Peer average: 5.6%

EEP: 7.8%

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 2013

6

Distribution Growth Target

Organic growth platform supports distribution growth

2007 2008 2009 2010 2011 2012 2013 2017e

2.7% 4.2% - 3.8% 3.6% 2.1% -

7

65% 62%

19%

~$36 billion equity market cap

Strong investment grade

Proven track record: industry

leading EPS and DPS growth

5 year EPS CAGR of 14%

5 year DPS CAGR of 14%

Strategy aligned with

Partnership

Joint funding provides

Partnership financing flexibility

Strength of GP – Enbridge Inc.

8

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/MEP Natural Gas Pipelines

EEP/MEP NGL Pipeline Joint Venture

9

North Dakota System

Midcontinent System

Lakehead System

WCSB Supply Forecast vs. Pipeline

Takeaway Capacity*

OTHER

ENB

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

201

3-Q

1

20

14

-Q1

201

5-Q

1

201

6-Q

1

201

7-Q

1

20

18

-Q1

201

9-Q

1

202

0-Q

1

202

1-Q

1

20

22

-Q1

MMbpd

2013 Enbridge Supply Forecast 2013 Enbridge Upside Supply Forecast Optimal Pipeline Capacity

• Keystone XL

• ENB Northern Gateway

• TransMountain Expansion

• Energy East

*Includes Bakken entering ENB Mainline

10

Supply Forecast

Bakken Crude Oil Supply Forecast vs. Pipeline

Takeaway Capacity

Range of External Supply Forecasts

Tesoro Mandan Refinery

Enbridge Berthold Rail ND

Baker Take-away (Platte)

Plains Bakken North

Enbridge Sandpiper

0.0

0.5

1.0

1.5

2.0

2.5

2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

MMbpd

Enbridge Bakken Expansion Program

Enbridge North Dakota system

11

Commodity Price Fundamentals Driving

Market Access Strategy

$115

$110

$92

Alberta Light

Bakken

Brent

Maya

Asia

$92

$109

LLS

WCS

$97

$79

$103

Light Crude

Heavy Crude

$105

WTI

Light Differentials

Brent – WTI $7

LLS – WTI $6

Asia – WTI $12

WTI – Bakken $6

WTI - Alberta

Light

$11

Heavy Differentials

Maya – WCS $13

Asia – WCS $26

Significant Infrastructure Investment Opportunities

February 27, 2014 prices (in US$/bbl)

North American Supply

North American Demand

Public Opposition to Infrastructure

Transportation Bottlenecks

Volatile Price Differentials

12

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

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

13

Providing New Market Access

14

Norman Wells

Zama

Edmonton

Fort McMurray

Portland

Seattle

Casper

Montreal

Salt Lake City

Patoka

Cushing

Superior

Chicago

Clearbrook

Regina

Flanagan

Hardisty

Toledo Sarnia

Buffalo

Houston

St. James

Cromer St. John

+600 kbpd

Heavy

+80 kbpd

Heavy

+250 kbpd Light

+50 kbpd Heavy

+300 kbpd Light

Western USGC

Access

Eastern Access

Light Oil Market

Access

+50 kbpd Light

Opening New Markets for up to 1.7 million barrels per day + ~1.0 MMbpd of Heavy and + ~0.7 MMbpd of Light

+50 kbpd Light

Nanticoke +250 kbpd

Heavy

Organic Growth Projects:

Commercially secured

Low risk framework

Long-term contracts

EEP Lakehead & North Dakota

Systems

Montreal Gretna

Regina

Hardisty

Kerrobert

Toledo

Buffalo

Edmonton

Houston

Fort McMurray

Cromer

Cushing

Patoka

Chicago/ Flanagan

Sarnia

Superior

Port Arthur

Market Access Programs

15

Westover

+600

kbpd

+300

kbpd

+440

kbpd

+80

kbpd

+300 kpbd

2013

• Bakken Pipeline Expansion+ Berthold Rail - EEP

• Line 5 Expansion (+50 kbpd) - EEP

• Line 62 Expansion (+105 kbpd) - EEP

• Line 9A Reversal (+50 kbpd) - ENB

• Toledo Pipeline Partial Twin (+80 kbpd) - ENB

• Seaway Pipeline Expansion (+400 kbpd) - ENB

2014

• Line 6B Replacement (+260 kbpd) - EEP

• Line 67 (+120 kbpd) (1)- EEP

• Line 61 (+160 kbpd) - EEP

• Line 9B Reversal + Expansion (+300 kbpd) - ENB

• Flanagan South Pipeline (+585 kbpd) - ENB

• Seaway Twin + Lateral (+450 kbpd) - ENB

2015

• Line 67 (+230 kbpd) - EEP

• Line 61 (+640 kbpd) - EEP

• Chicago Area Connectivity (+570 kbpd) – EEP

• Southern Access Extension (+300 kbpd) - ENB

• Edmonton to Hardisty (+570 kbpd) - ENB

2016

• Sandpiper Pipeline (+225/+375 kbpd) – EEP

• Line 6B Expansion (+75 kbpd) - EEP

Market Access Programs Bolster Lakehead System Utilization

EEP Lakehead &

North Dakota systems

2014 EEP Project In-Service:

Mainline Expansion(1) ~$0.2B

capital (3Q)

Line 6B Replacement ~$1.7B

capital (1Q/3Q)

(1) Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions.

Placed $1.2B assets in-service during 2013

Bakken Expansion – Sandpiper Pipeline

Clearbrook

Sarnia

Patoka

Toledo

Montreal

Westover

Hardisty

Cushing

Sandpiper Pipeline

Sandpiper ($2.6 B)

• Scope: 610 mile, 24”/30” pipeline

• Capacity: ~ 225 kbpd/375 kbpd

• Target in-service: Early 2016

• Marathon Funding:

37.5% of construction for ~27% equity

interest in EEP ND system

Low risk framework (ship-or-pay/COS)

Anchor Shipper secured

Regina

Gretna

Chicago Flanagan

16

Natural Gas and NGL Midstream Business

Anadarko System Ajax Processing Plant in service 3Q 2013

Texas Express NGL System In service 4Q 2013

North Texas System

East Texas System Beckville Processing Plant expected in service 1Q 2015

Petal

Logistics and Marketing 250 transport trucks, 300 trailers, 205 rail cars, TexPan Liquids Rail Facility

17

Business Opportunities – Natural Gas

and NGL Midstream

EAGLEBINE

CLINE SHALE

• Accretive growth • Capture rich gas processing opportunities • New pipeline laterals, NGL laterals, and

compression projects • Increase processing capabilities

• System optimization • Pursue accretive acquisitions

• Extend geographic reach • Complement and diversify existing asset footprint

• Enhance end-market access • Expand condensate treating, stabilization,

and liquids takeaway • Pursue vertical integration opportunities • Specialty services for off-spec products

Gathering, Processing & Transportation Logistics & Marketing

COTTON VALLEY

Optimize Asset and Commodity

Value

Market Origination

& Downstream

Pathing

Bundled Service Offering

Risk Management

Gathering, Processing &

Transportation

Natural Gas Marketing

Condensate Marketing

NGL Logistics & Marketing

Operational Reliability & Project Execution

19

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

Reliability

Project

Execution

Project

Development

Proven track record: on-time & on-budget

Supply Chain

Management

Construction

Experience

Life Cycle

Gating Control

Regulatory &

Permitting

Major

Projects

Business Mix & Risk Profile

20

Liquids Pipelines

~90%

Natural Gas

~10%

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.

*Note: based on 2014 forecast (consolidated basis)

Delivering Low-Risk Sustainable Growth

21

(1) Eastern Access and Mainline Expansion liquids expansion projects jointly funded by EEP & ENB. Sandpiper construction funded 37.5% by Marathon Petroleum Corp.

(2) Natural Gas project capital to be proportionately funded between EEP and Midcoast Energy Partners, L.P (MEP).

(3) Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions.

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 (1)

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 (3)

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 (2)

Ajax Plant

Texas Express NGL Pipeline JV

Beckville Plant

Distribution coverage strengthens as growth projects enter service

Midcoast Energy Partners IPO

Gas & Liquids Operations

Gas-Focused Operations Liquids-Focused Operations

Enhances Strategic Focus of Each Partnership

Dual Funding Sources to Support Growth

Creates Drop-Down Opportunity for MEP

Pa

st

Sta

te

Cu

rre

nt

Sta

te

22

Near-term Actions

1st Drop-Down post-IPO mid-2014 (~$300 – $500mm)

Drop-down remaining interests in gas business

to MEP within five years Nea

r Te

rm

Executing on our Financing Plan

23

Enhanced financing flexibility

Matches timing of permanent

funding with project cash flows

Strengthens credit metrics

Supportive general partner

MEP provides additional source

of capital through drop-downs

$1.2 Billion Preferred Unit Private

Placement

Exercise Joint Funding Option +$720MM

Accounts Receivable Sale

EEQ public offering +$500MM

Upsized credit facilities +$525MM

Midcoast Energy Partners IPO +$675MM*

Sandpiper JV with Marathon +$975MM

2013 Financing Actions

Manageable funding outlook

*Proceeds distributed to EEP from the MEP IPO include net proceeds from the public offering , in addition to proceeds from the overallotment exercise, plus MEP borrowings, less fees associated with the revolving credit facility and working capital agreement.

Funding Plan 2014-2017 (unconsolidated)

Debt

Total Requirement 1.2

2014 – 2017 Maturities 0.9

Debt Requirement 2.1

Equity

Total Requirement 1.2

EEQ PIK 0.6

Equity Requirement 0.6

24

Financing Options

Bank Credit Facility

Floating Rate Note

Term Debt

Hybrid Securities

Additional MEP Drop-Downs

Hybrid Securities

Private Placement

ATM program

EEP/EEQ Common Unit Offering

Uses/(Sources)

Secured Growth Capital 7.0

Maintenance Capital 0.4

Joint Funding Call Back on Lakehead Expansions 0.7

8.1

ENB Joint Funding (2.1)

Sandpiper Joint Funding (1.0)

MEP Drop-Downs +/- (2.6)

Net Funding Required 2.4

Equity funding requirements minimal; capacity for further growth investment

($billion)

Key Takeaways

25

• Top priorities: system integrity, safety and project execution

• Liquids growth projects collectively transform the

Partnership to lower risk business model

• Minimal equity funding requirements

• First drop-down post-IPO to MEP mid-2014

• Coverage strengthens as organic growth projects enter

service

• Distribution growth: targeting 2% to 5% annual growth

• Supportive general partner

Financial Outlook 2014

*Adjusted EBITDA inclusive of non-controlling interest and other income. EBITDA from non-controlling interest

estimated at $355 million, which is inclusive of ~$30 million of other income associated with AEDC.

**Depreciation includes non-controlling interest component of ~104 million.

Earnings Outlook 2014

1,500

1,050

440

1,600

1,130

480

0

200

400

600

800

1,000

1,200

1,400

1,600

Adjusted EBITDA* AdjustedOperating Income

Depreciation**

$ m

illio

ns

Guidance Range

Available Liquidity

27

500

1,000

1,500

2011 2012 2013 2014e

$ m

illio

ns

Liquids Projects Deliver EBITDA Growth

Based on adjusted EBITDA.

Coverage 0.85x-0.95x; Cash Coverage 1.05-1.15x

2,463

165

0

500

1,000

1,500

2,000

2,500

12/31/2013

$ m

illio

ns

Credit Facilities Cash

$2,628

Volume Assumptions

28

Liquids Volumes (kpbd)

2013 2014e

Lakehead 1,816 2,000– 2,200

North Dakota (1) 236 326 – 346

Mid-Continent 201 200 – 220

Total 2,253 2,526 – 2,766

Natural Gas Volumes (Mmbtu/d)

NGL Production (Bpd)

2013 2014e

Anadarko 949 850 – 900

East Texas 1,153 1,100 – 1,200

North Texas 317 300 – 320

Total 2,419 2,250 – 2,420

2013 2014e

88,346 88,000 – 92,000

Liquids Organic Growth Projects Bolster System Utilization

(1) North Dakota system volumes include physical volumes on North Dakota Trunkline and ship-or-pay volumes on Bakken Expansion. (2013: physical 171

kpbd; 2014 forecasted physical volumes range 230 - 250 kbpd)

Robust Western Canadian supply growth Strong downstream refining demand Liquids projects in-service

Growing Lakehead system deliveries forecast

Delivering Prudent Growth

29

(1) Eastern Access and Mainline Expansion Liquids projects to be jointly funded by EEP & ENB. Sandpiper construction to be funded 37.5% by Marathon Petroleum Corp. (2) Eastern Access has modest capital cost risk (3) Assumed capex is proportionally funded based on 61% current EEP ownership. (4) Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions.

($MM) Growth Capital

Net Capital EEP

Target In-Service Risk Profile

Bakken Growth Projects

Bakken Expansion 300 300 1Q13 10 year ship-or-pay

Bakken Rail 145 145 1Q13 3 year ship-or-pay

Bakken Access 100 100 2Q/3Q13 Volume Risk

Sandpiper (1) 2,600 1,625 early 2016

Sandpiper:

Ship-or-pay/Cost of Service

Eastern Access &

Mainline Expansions

30 year Cost of Service

No volume risk

No capital risk (2)

Eastern Access (1)

Line 6B Replacement, Line 5,

Line 62 expansion 2,100 525 2Q 2013 – 2014

Line 6B Expansion + tankage 400 100 early 2016

US Mainline Expansion (1)

Line 67 (Border to Superior) (4)

Line 61 (Superior to Flanagan) 1,900 475

Phase 1 3Q14;

Phase 2 2015-2016

Chicago Connectivity (Line 62 twin) 500 125 2H 2015

Ajax Plant 230 230 4Q13 Commodity & volume risk

Texas Express NGL Pipeline 400 400 4Q13 10 year ship-or-pay; with additional

5 year dedication

Beckville Plant(3) 145 88 2015 Commodity & volume risk

$8,820 $4,113

Organic growth secured by long-term low risk commercial structures

Liq

uid

s

Ga

s

Bakken Expansion Program

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

• 210 kbpd current

• Bakken Expansion +145 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 (3Q13)

Berthold Rail Program

EEP pipeline takeaway will reach 580 kbpd with next phase of expansion

Capital = $3.1B

to Superior

Growth Projects:

Commercially secured

Low-risk framework

Long-term contracts

30

Eastern Access Growth Projects

31

Clearbrook

Superior

Sarnia

Chicago

Patoka

Toledo

Montreal

Westover

3

1

4

5

Cushing

EEP/ENB joint funded

ENB

EEP Eastern Access Projects ($2.5B)

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

31

Western U.S. Gulf Coast Access

32

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

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

32

North American Crude Oil Supply Growth

(2013 – 2025)

33

Bakken

Eagle Ford

Permian Basin

Other

Niobrara

Oil Sands

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

Heavy Light

Cardium, Viking, Duvernay

Sources: Enbridge Internal Forecast and External Forecasts

+ 7 MMbpd by 2025

MMbpd

North American Crude Oil Demand

34 Source: StatsCan, EIA, Enbridge Internal Forecasts

Light Markets

• East Coast

• Eastern PADD II

• PADD III

Heavy Markets

• PADD II

• PADD III 34

Impact of Line 6B Incident

35

As of September

30, 2013

Booked in Q4

2013Total to Date

Total Costs $1,035 $87 $1,122

Less: Insurance Recoveries $547 $0 $547

Total Normalized $488 $87 $575

Estimated Costs*

*Includes $29.6 million in fines and penalties associated with the Line 6B incident. Due to the absence of sufficient

information, we cannot provide a reasonable estimate of our liability for additional fines and penalties that could be

assessed in connection of the Line 6B incident. As a result, except for the penalties disclosed herein, we have not

recorded any liability for expected fines and penalties.

Unaudited amounts, $ in millions. Represents life-to-date amounts pursuant to impact of the Line 6B incident.

Major Canadian and US Crude Oil Pipelines and

Refineries

36

36