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. Review of 2013

2. Funding Outlook

3. Liquids Pipelines Growth

4. MEP Strategic Rationale

5. 2014 Financial Guidance

6. Question & Answer

3

2013 Financial Summary

4

($millions, except per unit amounts ) 4Q 2013 4Q 2012 FY 2013 FY 2012

Adjusted EBITDA1 $303.3 $267.5 $1,143.4 $1,144.1

Adjusted Net Income2 $73.1 $87.2 $304.5 $ 410.2

Adjusted Net Income per unit2 $0.12 $0.18 $0.54 $0.99

Unaudited; adjusted results exclude the impact of: (a) additional environmental costs, net of insurance recoveries, associated with the Line 6B incident; 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. 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 $58.2 million in 2013; $22.4

million in 4Q13.

Financial Results

As-declared Coverage Ratio

0.70x

0.79x 0.82x 0.89x

0.00x

0.20x

0.40x

0.60x

0.80x

1.00x

2013 2012

Cash coverage

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

2,463

1,283

165

228

0

500

1,000

1,500

2,000

2,500

12/31/2013 12/31/2012

$ m

illio

ns

Credit Facilities Cash

$1,511

$2,628

Available Liquidity

Liquids Segment Results

5

1.74 1.84

1.68 1.83

1.92

0.21

0.22

0.17

0.22 0.20 0.17

0.13

0.15

0.21 0.20

-

0.50

1.00

1.50

2.00

2.50

4Q12 1Q13 2Q13 3Q13 4Q13

Volu

me b

y S

yste

m (

mm

bpd)

Lakehead Mid-Continent North Dakota

133.0

154.3

167.9

150.2

185.8

0

50

100

150

200

4Q12 1Q13 2Q13 3Q13 4Q13

$ 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

6

42.9

26.4

15.7 17.3

4.0

0

10

20

30

40

50

4Q12 1Q13 2Q13 3Q13 4Q13

$ m

illio

ns

998 964 972 957 902

1,233 1,252 1,211 1,120 1,028

333 332 344 314

292

-

50

100

150

200

250

300

350

400

-

500

1,000

1,500

2,000

2,500

3,000

4Q12 1Q13 2Q13 3Q13 4Q13

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

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.

0

20,000

40,000

60,000

80,000

100,000

4Q12 1Q13 2Q13 3Q13 4Q13

NG

L P

rod

ucti

on

(b

pd

)

Adjusted Operating Income Volumes / Rig Count

4Q13 Operating Headwinds: • Producer freeze-offs • Unplanned downtime

2013 Review

Market Headwinds Impacted Financial Performance

System integrity and operational reliability focus

$1.8 Billion of assets placed into service ~ FY cash flows in 2014

Tangible Progress on Funding Plan • Preferred Unit Private Placement + $1.2 Billion

• Exercise Joint Funding Option +$720MM

• Accounts Receivable Sale

• EEQ Public Offering +$500MM

• Upsized Credit Facilities +$525MM

• Midcoast Energy Partners IPO +$675MM

MEP IPO additional funding source for Liquids Expansions

7

Alleviate Equity Overhang

Strengthen Credit

Metrics

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

8

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)

Providing New Market Access

9

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

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

10

Midcoast Energy Partners IPO

Gas & Liquids Operations

Gas-Focused Operations Liquids-Focused Operations

Dual Funding Sources to Support Growth

Creates Drop-Down Opportunity for MEP

Pa

st

Sta

te

Cu

rre

nt

Sta

te

11

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

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

$ p

er u

nit

Distribution Growth

12

500

1,000

1,500

2011 2012 2013 2014e

$ m

illio

ns

Liquids Projects Deliver EBITDA Growth

Based on adjusted EBITDA.

2007 2008 2009 2010 2011 2012 2013 2016e

2.7

%

4.2

%

_

3.8

%

3.6

%

2.1

%

_

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

Volume Assumptions

13

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

Forecasted Capital Expenditures

110

200

1,350

$0

$500

$1,000

$1,500

$2,000

2014e

$ m

illi

on

s

Maintenance Natural Gas Liquids

Capital Expenditures 2014 Breakdown

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 250

US Mainline Expansions1 160

Sandpiper1 315

Line 6B 75-mile Replacement 20

Liquids Integrity 270

Liquids Other Growth Enhancements 335

Beckville Gas Processing Plant2 70

NG Other Growth Enhancements2 130

Core Maintenance2 $110

Total $1,660

14

Key Takeaways

15

• Top priorities: system integrity, safety and project

execution

• 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

• Maintaining investment grade credit rating is a priority

APPENDIX

17

Distribution Coverage and Liquidity

Adjusted Net

Income* 304.5

Cash Distribution

711.2

Dep. - Maint. Capex 224.0

PIKs 128.5

-50

50

150

250

350

450

550

650

750

850

Distributable Cash Flow As Declared Distribution

$ m

illio

ns

$586.7

$839.7

Full Year Coverage Ratio: 0.70x Available Liquidity

*Unaudited; adjusted results exclude the impact of: (a) additional environmental costs, net of insurance recoveries, associated with the incidents on Lines 14 and 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.

Adjusted net income after non-controlling interest and deferred distribution attributable to preferred unitholders.

2,463

1,283

165

228

0

500

1,000

1,500

2,000

2,500

12/31/2013 12/31/2012

$ m

illio

ns

Credit Facilities Cash

$1,511

$2,628

18

Deferred Pref Distribution

58.2

Montreal Gretna

Regina

Hardisty

Kerrobert

Toledo

Buffalo

Edmonton

Houston

Fort McMurray

Cromer

Cushing

Patoka

Chicago/ Flanagan

Sarnia

Superior

Port Arthur

Market Access Programs

19

Westover

+600

kbpd

+300

kbpd

+440

kbpd

+80

kbpd

+300 kpbd

2013

• 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

Organic Growth Projects:

Commercially secured

Low risk framework

Long-term contracts

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.

Delivering Low-Risk Sustainable Growth

20

(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