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; (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;

and (8) inability of any party to consummate the proposed transaction.

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.

Investment Highlights

3

*Enterprise Value as of 7/31/14; **Return CAGR since inception (nominal)

One of the longest established pipeline MLPs (1991)

Track record of consistently delivering cash distributions (never reduced)

Largest pipeline transporter of crude oil production growth from Western Canada

Largest pipeline transporter of crude oil production growth from Bakken formation

$0

$20,000

$40,000

$60,000

$80,000

$100,000

$120,000

$140,000

$160,000

$180,000

Total Shareholder Return

1991 2013

Enterprise Value -

Large-Cap MLP

Commercially

secured organic

growth underway

Strong Investment Grade (S&P, Moody’s, DBRS) Low-risk transformative

growth underway

~$1.8 billion of growth capital placed in service

~$3.1 billion of funding secured

IPO carve-out of natural gas & NGL business ~ position EEP as pure-play liquids pipeline MLP

Highlights

2013 Highlights

4

Strong Business Fundamentals: Strength & Stability

Migrating to a Much Lower Risk

Business Model

Strong General Partner

Stable Distributions & Prudent Growth

Attractive Yield

Investment Proposition

4

65% 62%

19%

• Owner and operator of largest crude

oil pipeline system

• ~$43 billion equity market cap

• Strong investment grade (A-, Baa1)

• 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

• ~$37 billion commercially secured

organic growth program underway

Strength of GP – Enbridge Inc.

5

ENB: North American leader in

energy delivery

Strategic Position

6

Norman Wells

Zama

Portland

Seattle

Casper

Montreal

Salt Lake City

Patoka

Cushing

Ottawa Superior

Chicago

Clearbrook

Regina

Flanagan

Hardisty

Toledo

Toronto

Sarnia Buffalo

Wood

River

Edmonton

Fort McMurray

Houston

St. James

Philadelphia

Cromer St. John

WCSB

BAKKEN

EEP Contract Storage

EEP Liquids Pipelines

ENB Liquids Pipelines

Competitive Advantages

• Refiners

– Access to multiple crude streams

• Producers

– Access to multiple premium markets

• Flexible system

• Size and scale unmatched

– Will expand to ~2.85 MMb/d in 2017

Positioned for Long-Term Growth

• Direct connection to growing supply basins (Heavy

& Light)

High quality customer base

ENB and EEP Strategically Aligned

OTHER

ENB

0.0

1.0

2.0

3.0

4.0

5.0

6.0

7.0

8.0

9.0

MMb/d

2013 Enbridge Upside Forecast Optimal Pipeline Capacity

Supply Forecast

WCSB Supply Forecast vs. Pipeline

Takeaway Capacity*

7

*Includes Bakken entering ENB Mainline ex-Superior Sources: Enbridge Internal Forecast

Keystone XL

ENB Northern Gateway

TransMountain Expansion

Energy East

8

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

MMb/d

Enbridge Bakken Pipeline

Enbridge North Dakota system

* Sandpiper construction to be funded 37.5% by Marathon Petroleum Corp; Marathon to assume ~27% equity participation in expanded EEP North Dakota System after

Sandpiper in-service.

Bakken Crude Oil Supply vs. Pipeline

Takeaway Capacity

North American Crude Oil Price

Fundamentals

9

$104

$101

$90

Alberta Light

Bakken

Brent

Maya

Asia

$88

$96

LLS

WCS

$87

$77

$94

Light Crude

Heavy Crude

$99

WTI

Light Differentials

8/27/14 1/30/13

Brent – WTI $7 $19

LLS – WTI $2 $18

Asia – WTI $10 $22

WTI – Bakken $7 $3

WTI - Alberta Light $6 $6

Heavy Differentials

8/27/14 1/30/13

Maya – WCS $13 $39

Asia – WCS $22 $44

Significant Infrastructure Investment Opportunities

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

North American Supply

North American Demand

Transportation Bottlenecks

Volatile Price Differentials

Providing New Market Access

10

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

Montreal Gretna

Regina

Hardisty

Kerrobert

Toledo

Buffalo

Edmonton

Houston

Fort McMurray

Cromer

Cushing

Patoka

Chicago/ Flanagan

Sarnia

Superior

Port Arthur

Market Access Programs

11

Westover

+600

kbpd

+300

kbpd

+440

kbpd

+80

kbpd

+320 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 61 (+160 kbpd) - EEP

• Line 67 (+120 kbpd) (1)- EEP

Seaway Twin + Lateral (+450 kbpd) - ENB

• Line 9B Reversal + Expansion (+320 kbpd) - ENB

• Flanagan South Pipeline (+600 kbpd) - ENB

2015

• Line 67 (+230 kbpd) – ENB/EEP

• Line 61 (+640 kbpd) - EEP

• Line 78 Chicago 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 (+70kbpd) - EEP

Market Access Programs Bolster Lakehead System Utilization

(1) Phase 1 of Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated

by temporary system optimization actions.

2017

• Line 3 Replacement –ENB/ EEP

Lakehead System

12

Project Execution – 2014 In-Service

Eastern Access: Ln 6B Replacement

• 160 miles of Line 6B replacement

entered service in May

• Remaining 50 mile replacement

construction underway (early 4Q

2014 in service)

• ~$2.1 billion capital

Mainline Expansions

• Line 61- expansion from 400kbpd to

560kbpd between Superior and

Flanagan entered service August

• ~$0.2 billion capital

* Jointly funded 25% EEP / 75% ENB

Commercially Secured

30 year Cost of Service

Bakken Expansion – Sandpiper Pipeline

Clearbrook

Superior

Sarnia

Chicago

Patoka

Toledo

Montreal

Westover

Hardisty

Cushing

Regina

Gretna

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

Petition for Declaratory Order

approved by FERC May 2014

Flanagan

13

• Line 3:

– Part of Enbridge mainline system

– Replace all remaining segments

from Hardisty to Superior with

latest available high strength

steel and coating technology

• EEP Capital Investment:

– border to Superior ~ $2.6 billion

capital

– to be joint funded with ENB

• Expected Completion:

– 2nd Half of 2017

• 30 year Cost-of-Service

– 15 year primary term

• Shipper Support (CAPP/RSG)

Line 3 Replacement

14

15

Commercial Structure & Risk Profile

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, after deducting non-controlling interest.

Assumes Natural Gas business dropped down to MEP within five years.

0.0%

20.0%

40.0%

60.0%

80.0%

100.0%

2011 2012 2013 2014 2015 2016 2017

59%

23%

18%

Cost-of-Service/Take-or-Pay

Commodity Sensitive

Fee-Based 24%

76%

(Unconsolidated view)

Operational Risk Management Program

Industry Leadership

Third Party Damage

Avoidance and

Detection

Incident Response

Capacity

Employee and

Contractor

Occupational Safety

Public Safety and

Environmental

Protection

Integrity Management

Leak Detection

Capability and

Control Systems

• State-of-the art Liquids Pipelines control center

• Most extensive maintenance, integrity and inspection program in the history of the

North American pipeline industry

• Liquids Pipelines completed 615 in-line inspections and 8,975 verification digs (2010-

2013)

Priority One – Focus on Safety & Operational Reliability

16

Distribution Growth Target

17

Organic growth platform supports distribution growth

2007 2008 2009 2010 2011 2012 2013 2014 2017e

2% - 5% Annual Growth Target

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

Momentum to

achieve higher

end of growth

target

Executed Drop-Down to MEP Drop-Downs Bolster Funding Program

18

Past

Sta

te

Cu

rren

t S

tate

EEP: ‘Pure-Play’ Liquids Pipeline MLP

MEP: ‘Pure-Play’ Natural Gas & NGL Midstream MLP

Gas & Liquids Operations

• Executed Drop-Down to MEP July 1, 2014

o Sold 12.6% interest in Midcoast Operating for $350 million

• Drop-down remaining interests in gas business to MEP through 2017

Gas-Focused Operations Liquids-Focused Operations

Drop-down proceeds largely mitigate equity funding requirements

Equity Restructure

Improves EEP’s cost of capital

Increases distributable cash

available to LP unit holders

Establishes momentum for

distribution growth

Enhances acquisition

competitiveness

Prospective Benefits

(1) Revised Structure Incentive pertains to distributions paid by EEP in excess of

$0.5435/unit per quarter. 19

EEP Equity Restructuring

Strengthen and position EEP as future drop-down vehicle

Long-Term ENB Liquids Drop-Down

Potential: $10 Billion +

20

2017e

Distributable

Cash

ENB Drop-Down Backlog:

Upsize Option- Eastern Access and Mainline Expansions

Alberta Clipper

Eastern Access

Mainline Expansions

Line 3 Replacement

Spearhead

Flanagan South

Seaway/Seaway Twin

Other

Pipeline System Upsize Option Capital Cost/

Book Value*

Eastern Access $0.4 (2016/2017) ~ $1.5

Mainline Expansion $0.4 (2016/2017) ~ $1.4

Alberta Clipper - ~ $0.8

Line 3 Replacement** $0.4 (2018) ~ $0.9

Flanagan South - ~ $2.8

Seaway/Seaway Twin - ~ $2.4

Substantial drop-down opportunities from parent supports long-term growth outlook

* Estimated capital cost or net book value of assets held by Enbridge Inc.

** Line 3 Replacement Joint Funding Agreement under consideration by a Special Committee of the independent Board of Directors., including an option to upsize EEP

ownership by 15% one year after the in-service date.

~ $10B

($ Billions)

Examples:

Key Takeaways

21

• Strategic position supported by strong business fundamentals

• Secured Liquids projects collectively transform the Partnership

to an even lower risk business model

• Coverage strengthens as organic growth projects enter service

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

• Minimal equity funding requirements

• General Partner is strategically aligned with and invests in EEP

Safety and operational reliability are cornerstones that underpin

our business and growth outlook

Corporate Structure

23

Corporate structure as of August 14, 2014

48.4% LP interest

46% LP

interest

2% GP interest

52% LP interest

51.5% LP

interest

Public

Unitholders

88.3% of

listed shares

Public

Unitholders

2% GP interest

29.9% LP interest (indirect)

Enbridge Inc.

(NYSE: ENB)

(Baa1 / A-)

Enbridge Energy Management,

L.L.C.

(NYSE: EEQ)

16.7% LP

interest (I-units)

11.7% of listed shares

100% voting interest

Enbridge Energy Partners, L.P.

(NYSE: EEP)

(Baa2 / BBB)

51.6% LP interest

Midcoast Operating, L.P.

“Midcoast Operating”

Midcoast Energy Partners, L.P.

(NYSE: MEP)

Public

Unitholders

Enbridge Inc. owns

~34% of EEP