Legal Notice

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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 of this presentation. 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

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*Enterprise Value as of 5/31/14; **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

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

Strong Investment Grade (S&P, Moody’s, DBRS)

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

• ~$40 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

• ~$36 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

9.0MMb/d

2013 Enbridge Forecast 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

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$114

$110

$96

Alberta Light

Bakken

Brent

Maya

Asia

$95

$106

LLS

WCS

$97

$83

$103

Light Crude Heavy Crude

$104

WTI

Light Differentials

6/5/14 1/30/13

Brent – WTI $7 $19

LLS – WTI $3 $18

Asia – WTI $11 $22

WTI – Bakken $6 $3

WTI - Alberta Light $8 $6

Heavy Differentials

6/5/14 1/30/13

Maya – WCS $13 $39

Asia – WCS $21 $44

Significant Infrastructure Investment Opportunities

June 5, 2014 prices (in US$/bbl)

North American Supply

North American Demand

Transportation Bottlenecks

Volatile Price Differentials

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Providing New Market Access

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

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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) - 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 (+70 kbpd) - EEP

Market Access Programs Bolster Lakehead System Utilization

(1) 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

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Project Execution – 2014 In-Service Eastern Access: Ln 6B Replacement

• 160 miles of Line 6B replacement entered 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

• 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

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Bakken Expansion – Sandpiper Pipeline

Clearbrook

Superior

Sarnia

Chicago

Patoka

Toledo

Montreal

Westover

Hardisty

Cushing

Regina

Gretna

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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 the FERC May 2014

Flanagan

Safety and Operational Reliability

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Risk Management

• Risk Policy, Risk Framework, Risk Culture Survey + Training

Inline inspection (ILI)

• Significant dig program 3,400 pipe joints examined followed with non-destructive testing

• Research and Development in tool enhancements - Medical imaging technology

On-line sensors

• Pressures/cycling, pipe movement, external & internal corrosion, vibration

Surveys

• Pipe depth, river crossing and geotechnical conditions, corrosion control, 3rd party activity

Incident Response

• Focused Emergency response tactical plans

Health & Safety

• Process safety management implementation

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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%

2011 2012 2013 2014 2015 2016 2017

59%

23%

18%

Cost-of-Service/Take-or-Pay

Commodity Sensitive

Fee-Based 24%

76%

(Unconsolidated view)

Midcoast Energy Partners IPO (MEP) Drop-Downs Bolster Funding Program

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Past

Sta

te

Cur

rent

Sta

te

Nea

r Ter

m

EEP: ‘Pure-Play’ Liquids Pipeline MLP MEP: ‘Pure-Play’ Natural Gas & NGL Midstream 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)

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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.

Strengthening Distribution Coverage

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Secured growth projects improve distribution coverage

0.00x

0.25x

0.50x

0.75x

1.00x

1.25x

2010 2011 2012 2013 2014e 2017e

Long Range Coverage Target

Guidance range

Cov

erag

e*

* Coverage includes EEQ paid-in-kind distribution.

Accretive growth underway Backed by long-term, low risk

commercial framework • cost-of-service • ship-or-pay

Highly certain distributable cash flow growth

Distribution Growth Target

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Organic growth platform supports distribution growth

2007 2008 2009 2010 2011 2012 2013 2017e

2% - 5% Annual Growth Target

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

Long-Term ENB Liquids Drop-Down Potential: $10 Billion +

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2017e

Distributable Cash

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 to be finalized 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

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• 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

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

• Strategically aligned, supportive general partner

Safety and operational reliability are cornerstones that underpin our business and growth outlook