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.

Agenda

1. Project Update

2. MEP Drop-Down

3. Funding Outlook

4. Financial Results

5. Question & Answer

3

• 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

4

Montreal Gretna

Regina

Hardisty

Kerrobert

Toledo

Buffalo

Edmonton

Houston

Fort McMurray

Cromer

Cushing

Patoka

Chicago/ Flanagan

Sarnia

Superior

Port Arthur

5

Market Access Programs

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 67 (+120 kbpd) (1)- EEP

• Line 61 (+160 kbpd) - EEP

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

• Flanagan South Pipeline (+600 kbpd) - ENB

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

2015

• Line 67 (+230 kbpd) – ENB/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 (+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

Organic Growth Projects:

Commercially secured

Low risk framework

Long-term contracts

6

Project Execution – 2014 In-Service

Eastern Access: Ln 6B Replacement

• 160 miles of Line 6B replacement is

on target to enter service in May

• ROW and permitting for the

remaining 50 mile replacement

secured, construction to begin this

spring for Q3 2014 in service date

• ~$2.1 billion capital

Mainline Expansions

• Line 61- expansion from 400kbpd to

560kbpd between Superior and

Flanagan (3Q 2014 in-service)

• ~$0.2 billion capital

* Jointly funded 25% EEP / 75% ENB

Commercially Secured

30 year Cost of Service

7

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, excluding 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%

2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

59%

23%

18%

Cost-of-Service/Take-or-Pay

Commodity Sensitive

Fee-Based 24%

76%

(Unconsolidated view)

Execute Drop-Down to MEP Mid-Year Drop-Downs Bolster Funding Program

8

Pa

st

Sta

te

Cu

rre

nt

Sta

te

Ne

ar

Te

rm

EEP: ‘Pure-Play’ Liquids Pipeline MLP

Additional Funding Source to Support Growth

Significantly Mitigates EEP Equity Needs

Gas & Liquids Operations

• First Drop-Down to MEP targeted mid-2014 (~$300–$400 million)

• Drop-down remaining interests in gas business to MEP within

five years

Gas-Focused Operations Liquids-Focused Operations

Funding Plan 2014-2017 (unconsolidated)

9

Debt

Total Requirement 2.4

2014 – 2017 Maturities 0.9

Debt Requirement 3.3

Equity

Total Requirement 1.2

EEQ PIK (0.6)

Equity Requirement 0.6

Financing Options

Additional MEP Drop-Downs

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 9.4

Maintenance Capital 0.4

Joint Funding Call Back on Lakehead Expansions 0.7

10.5

ENB Joint Funding* (3.3)

Sandpiper Joint Funding (1.0)

MEP Drop-Downs +/- (2.6)

Net Funding Required 3.6

Equity funding requirements manageable

($billion)

* Joint funding with Enbridge Inc. includes estimated 50% funding by Enbridge Inc. for U.S. component of Line 3

Replacement program and 50% estimated funding by EEP. Participation levels being finalized and approved by

Independent Special Committee.

Financial Summary

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($millions, except per unit amounts ) 1Q 2014 1Q 2013

Adjusted EBITDA1 $338.7 $281.0

Adjusted Net Income2 $102.9 $95.7

Adjusted Net Income per unit2 $0.20 $0.21

Unaudited; adjusted results exclude the impact of non-cash, mark-to-market net gains and losses; among other adjustments. Refer to the Non-GAAP Reconciliation tables presented

in the supplemental slides. 1Adjusted EBITDA includes non-controlling interest. 2Adjusted net income after non-controlling interest and deferred distribution attributable to preferred unitholders. Preferred units deferred distribution of $22.5 million in 1Q 2014.

Financial Results

As-declared Coverage Ratio *

0.89x

0.79x

1.07x 0.92x

0.00x

0.20x

0.40x

0.60x

0.80x

1.00x

2014 2013

Cash coverage

Coverage including PIK distribution * Coverage metric excludes deferred distribution attributable to preferred unitholders.

First Quarter 2014 Highlights

Strong Lakehead System Deliveries

Strong North Dakota System

Deliveries

Full quarter contributions from

growth projects

Bakken Pipeline expansion

Bakken Berthold Rail

Bakken Access

Lakehead system expansions

Strengthening Distribution

Coverage

Liquids Segment Results

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1.84 1.68

1.83 1.92 2.00

0.22

0.17

0.22 0.20

0.21 0.13

0.15

0.21 0.20

0.25

-

0.50

1.00

1.50

2.00

2.50

1Q13 2Q13 3Q13 4Q13 1Q14

Volu

me b

y S

yste

m (

mm

bpd)

Lakehead Mid-Continent North Dakota

154.3

167.9

150.2

185.8

205.2

0

50

100

150

200

1Q13 2Q13 3Q13 4Q13 1Q14

$ m

illio

ns

Adjusted Operating Income Volumes

Unaudited; adjusted results exclude the impact of: (a) additional environmental costs, net of insurance recoveries, associated with the incident on Line 6B; and (b) non-cash, mark-to-

market net gains and losses; among other adjustments. Refer to the Non-GAAP Reconciliation tables presented in the supplemental slides.

Natural Gas Segment

12

26.8

15.7 16.8

4.4

8.8

0

10

20

30

40

50

1Q13 2Q13 3Q13 4Q13 1Q14

$ m

illio

ns

Unaudited; adjusted results exclude the impact of: (a) non-cash, mark-to-market net gains and losses; among other adjustments. Refer to the Non-GAAP Reconciliation tables

presented in the supplemental slides.

Adjusted Operating Income * Volumes / Rig Count

964 972 957 902 824

1,252 1,211 1,120 1,028 971

332 333 314

292 272

-

50

100

150

200

250

300

350

400

-

500

1,000

1,500

2,000

2,500

3,000

1Q13 2Q13 3Q13 4Q13 1Q14

Avera

ge R

ig C

ount

EE

P M

ain

Regio

ns

Vo

lum

e b

y S

yste

m

(mm

btu

/d in

th

ou

sa

nd

s)

Anadarko East Texas North Texas Rig Count

* During the first quarter of 2014, the Partnership changed its reporting segments. The Marketing segment was

combined with the Natural Gas segment to form one new segment called “Natural Gas”.

0

20,000

40,000

60,000

80,000

100,000

1Q13 2Q13 3Q13 4Q13 1Q14

NG

L P

rod

ucti

on

(b

pd

)

NGL Production attributable

to lost customer

Forecasted Capital Expenditures

Capital Expenditures

1 Eastern Access and US Mainline Expansion capital expenditures are forecasted net of joint funding, with assumed Enbridge Inc. 75% funding; Sandpiper capital

expenditures are forecasted net of 37.5% joint funding from Marathon Petroleum Corp. 2 Represents EEP’s share of Natural Gas capital expenditures of Midcoast Operating, L.P., (“MOLP”) which will be proportionately funded between EEP and Midcoast

Energy Partners, L.P (MEP). Forecast reflects base 61% funding by EEP and 39% by MEP.

Eastern Access1 265

US Mainline Expansions1 210

Sandpiper1 260

Line 6B 75-mile Replacement 15

Line 3 Replacement 100

Liquids Integrity 280

Liquids Other Growth Enhancements 260

Beckville Gas Processing Plant2 65

NG Other Growth Enhancements2 135

Core Maintenance2 $110

Total $1,700

13

2,345

2,798

89

160

0

500

1,000

1,500

2,000

2,500

3,000

3/31/2014 12/31/2013

$ m

illio

ns

Credit Facilities Cash

$2,434

$2,958

Available Liquidity*

Strong investment grade credit profile (BBB/Baa2)

*EEP’s available liquidity excludes credit available to its affiliates MEP and MOLP under

their credit agreement and also excludes MEP’s cash balance at period end.

Key Takeaways

14

• Strong Lakehead and North Dakota system deliveries

• Coverage continues to strengthen as organic growth

projects enter service

• Target first drop-down post-IPO to MEP mid-2014

• Manageable funding plan – minimal equity requirements

• Secured Liquids projects collectively further transform

the Partnership to an even lower risk business model

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

Safety and operational reliability are cornerstones that underpin

our business and growth outlook