INTRODUCTION Sanjay Lad, Director Investor Relations, Enbridge - - PowerPoint PPT Presentation

INTRODUCTION

Sanjay Lad, Director Investor Relations, Enbridge Energy Partners and Midcoast Energy Partners

2

Legal Notice

This presentation includes certain forward looking information (“FLI”) to provide investors and potential investors in any of Enbridge Energy Partners, L.P. (“EEP”), Enbridge Energy Management, L.L.C. (“EEQ”) and Midcoast Energy Partners, L.P. (“MEP”) with information about EEP, EEQ and MEP management’s assessment of the future plans and operations, which may not be appropriate for

• ther 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 the control or prediction of EEP, EEQ or MEP. 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 and MEP’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 and MEP or refineries, petrochemical plants, utilities or other businesses for which EEP and MEP transports products or to whom EEP and MEP 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 and MEP 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 EEP’s ownership in Midcoast Operating, L.P. are further qualified by the fact that MEP is under no obligation to buy any of our interests in Midcoast Operating, L.P., and EEP is 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, EEQ’s and MEP’s SEC filings, including its most recently filed Annual Report on Form 10-K and subsequently filed Quarterly Reports on Form 10-Q.

STRATEGIC OVERVIEW - EEP

Mark Maki, President, Enbridge Energy Partners

2

Key Messages

• Distribution sustainable
• Coverage strengthens as projects enter service;

highly certain cash flows

• Strong and aligned general partner
• Annual distribution growth target: 2% to 5%
• Unrivaled Liquids Pipeline asset position in

infrastructure MLP arena

Safety and operational reliability are cornerstones that underpin

• ur business and growth outlook
• Transformative organic growth program underway
• Supported by long-term, low-risk commercial structures
• Execute growth program
• Translate growth into financial success

3

Investment Highlights

*Enterprise Value as of 2/28/2014; **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) 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

65% 62% 19%

• Owner and operator of largest crude
• il pipeline system
• ~$37 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
• rganic growth program underway

Strength of GP – Enbridge Inc.

4

ENB: North American leader in energy delivery

Montreal Gretna Regina Hardisty Kerrobert Toledo Buffalo Edmonton

Houston

Fort McMurray Cromer Cushing Patoka Chicago/ Flanagan Sarnia Superior Port Arthur

5

Strategic Position

Westover

+600 kbpd

+300 kbpd +440 kbpd

+80 kbpd

+300 kpbd

Market Access Programs Bolster Strategic Position

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

substantially mitigated by temporary system optimization actions.

Growth Projects:



Commercially secured



Low-risk framework



Long-term contracts

Liquids Pipeline System Competitive Advantages:

• Scale post-2017: 2.85 million bpd
• Connected to rapidly growing

supply sources

• Access to premium markets
• Well positioned for extension to

new markets

• Established ROW
• Multiple lines: quality/reliability
• High quality customer base

Growth Projects In-Service :

2013

2014 2015 2016 2017

6

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.

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)

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Strengthening Distribution Coverage

Secured growth projects deliver highly certain cash flows

0.00x 0.25x 0.50x 0.75x 1.00x 1.25x 2010 2011 2012 2013 2014e 2017e

Long Range Coverage Target

Guidance range

Coverage*

* 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

8

Executing on Funding Plan

General Partner is aligned with and invests in EEP Enhanced financing flexibility Matches timing of permanent funding with project cash flows MEP provides additional source

• f capital through drop-downs

Strengthens credit metrics

 Preferred Unit Private Placement +$1.2 Billion

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.

 Accounts Receivable Sale + ~$400MM  Midcoast Energy Partners IPO +$675MM*  Sandpiper JV with Marathon +$975MM  Exercise Joint Funding Option +$720MM  EEQ public offering +$500MM

Alleviate equity overhang

9

Drop-Downs Bolster Funding Program

Past State Current State Near Term 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 mid-2014 (~$300–$500 million)
• Drop-down remaining interests in gas business to MEP

within five years

Gas-Focused Operations Liquids-Focused Operations

10

Growth Outlook

 Liquids Pipelines organic growth program underway

• New infrastructure, expansion and market access
• Highly certain returns and long term cash flows

 Execute on growth program

• Deliver projects on-time and on-budget
• Financial execution: translate organic growth into financial success
• Visible distribution growth
• Strengthen valuation

 Position the Partnership as a drop-down vehicle for Enbridge Inc.

• Substantial and attractive inventory of drop-down assets

11

Distribution Growth Target

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 +

2017e

Distributable Cash         

12

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

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

~ $10B

($ Billions)

Examples:

13

Operational Reliability & Project Execution

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

14

Key Takeaways

• Strategic position supported by strong business fundamentals
• Secured Liquids projects collectively further transform the

Partnership to even lower risk business model

• Coverage strengthens as projects enter service
• Distribution growth: targeting 2% to 5% annual growth
• Position the Partnership as a drop-down vehicle for Enbridge

Inc.

• Attractive long-term growth outlook
• Maintaining investment grade credit rating is a priority

Safety and operational reliability are cornerstones that underpin

• ur business and growth outlook

Corporate Structure

Corporate structure as of March 21, 2014

61% LP interest 46% LP interest 2% GP interest 52% LP interest 62.2% LP interest

Public Unitholders

88.3% of listed shares

Public Unitholders

2% GP interest 16.3% LP interest (indirect)

Enbridge Inc. (NYSE: ENB) (Baa1 / A-) Enbridge Energy Management, L.L.C. (NYSE: EEQ)

19.5% LP interest (I-units) 11.7% of listed shares 100% voting interest

Enbridge Energy Partners, L.P. (NYSE: EEP) (Baa2 / BBB)

39% LP interest

Operating Subsidiaries

100% ownership interest

Midcoast Operating, L.P. “Midcoast Operating”

Texas Express NGL System Joint Venture

35% ownership interest 100% interest (indirect)

Midcoast Energy Partners, L.P. (NYSE: MEP) Public Unitholders

Enbridge Inc. owns ~21% of EEP

15

LIQUIDS PIPELINES

Guy Jarvis, President, Liquids Pipelines, Enbridge Inc.

2

• Strong North American crude oil supply fundamentals
• Market access program bolsters competitive position
• Lakehead system ideally positioned
• Enbridge will continue to be premier liquids pipeline

system to provide access to multiple premium markets

• Transforming secured growth projects into operational

and financial success

Key Messages

Safety and operational reliability are cornerstones that underpin

• ur business and growth outlook

3

North American Crude Oil Supply Growth (2013 – 2025)

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

US Refining Crude Coverage

0.0 2.0 4.0 6.0 8.0 10.0 12.0 14.0 16.0 18.0

2013F 2015 2020 2025

US Production Waterborne Imports Imports from Canada

MMb/d

4

Sources: Enbridge Internal Forecast

North American Production Displaces Waterborne Imports

5

North American Crude Oil Price Fundamentals

$112 $106 $89

Alberta Light

Bakken Brent Maya Asia $94 $103 LLS WCS $94 $79 $100

Light Crude Heavy Crude

$102 WTI

Light Differentials Brent – WTI $6 LLS – WTI $3 Asia – WTI $12 WTI – Bakken $6 WTI - Alberta Light $6 Heavy Differentials Maya – WCS $10 Asia – WCS $23

Significant Infrastructure Investment Opportunities

March 20, 2014 prices (in US$/bbl)

North American Supply North American Demand Transportation Bottlenecks Volatile Price Differentials

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 Forecast 2013 Enbridge Upside Forecast Optimal Pipeline Capacity Supply Forecast

WCSB Supply Forecast vs. Pipeline Takeaway Capacity*

6

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

Keystone XL ENB Northern Gateway TransMountain Expansion Energy East

7

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

Strategic Position

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)

ENB and EEP Strategically Aligned

8

9

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

Market Access – Eastern Access

Superior Sarnia Chicago Patoka Toledo Montreal Westover Hardisty EEP/ENB Joint Funded ENB Funded 1 2 6 4 5 3 Cushing

10

1. Line 5 Expansion +50 Mb/d (In-Service) 2. Spearhead North Expansion +105 Mb/d (Line 62) (In-Service) 3. Line 6B Replacement +260 Mb/d (2014) 4. Line 9A Reversal +240 Mb/d (In-Service) 5. Line 9B Reversal +240 Mb/d (2014) 6. Toledo Pipeline Twin +80 Mb/d (In-Service)

1 2 3 4 5 6 Flanagan

Linking North American crude supply growth to eastern refining centers

11

Clearbrook Superior Sarnia Patoka Toledo Montreal Westover Hardisty Flanagan Chicago

EEP/MPC funded EEP/ENB joint funded ENB funded

Sandpiper Pipeline +225/+375 Mb/d (2016) Line 61 Expansion + 640 Mb/d (2016) Line 62 Twin +570 Mb/d (2015) Line 6B Expansion +70 Mb/d (2016) Line 9 Expansion +60 Mb/d (2014) Southern Access Extension +300 Mb/d (2015)

Gretna Cromer 1 2 4 5 6 4 1 3 5 6 Stockbridge

Market Access – Light Oil Market Access (LOMA)

Matching light oil supply growth to key markets

3 2

12

Cushing Houston Chicago/ Flanagan Port Arthur

1 3 2

4 5 EEP/ENB Funded ENB Funded Refining center

Heavy 43% Light 57% Western USGC Refining Processing Capability (~4,400 Mb/d)

Source: EIA and Enbridge’s internal estimates

Market Access – US Gulf Coast

12

Seaway Pipeline 400 Mb/d (In Service) Flanagan South Pipeline +585 Mb/d (2014) Seaway Pipeline Twin & Lateral +450 Mb/d (2014) Line 67 Expansion +350 Mb/d by 2015 (1) Line 61 Expansion +160 Mb/d by 2014

1 2 4

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

Linking North American crude supply growth to USGC refining centers

3 5

Bakken Infrastructure

Clearbrook

Gretna

Manitoba

Minot Lignite Weyburn

Cromer Berthold

Steelman Tioga Stanley

to Superior

Enbridge Mainline North Dakota System (EEP)

• 210 Mb/d

Bakken Pipeline (EEP, ENF)

• 145 Mb/d

Saskatchewan System (ENF) Bakken Access Program (EEP) 100 Mb/d Berthold Rail (EEP)

• 80 Mb/d

Sandpiper (EEP, MPC)*

• 225/375 Mb/d (Early 2016 ISD)

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

*Marathon Petroleum Corp. will fund 37.5% of Project Sandpiper cost and assume a ~27% equity interest in the EEP North Dakota system, once the project enters service.

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 filed with

FERC

• 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
• Shipper Support (CAPP/RSG)

15

Line 3 Replacement

Montreal Gretna Regina Hardisty Kerrobert Toledo Buffalo Edmonton

Houston

Fort McMurray Cromer Cushing Patoka Chicago/ Flanagan Sarnia Superior Port Arthur

16

Growth and Project Integration

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) – 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

Safety and Operational Reliability

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

17

Key Takeaways

18

• Strong North American crude oil supply fundamentals
• Market access program bolsters competitive position
• Lakehead system ideally positioned
• Enbridge will continue to be premier liquids pipeline system to

provide access to multiple premium markets

• Transforming secured growth projects into operational and

financial success Safety and operational reliability are cornerstones that underpin

• ur business and growth outlook

MAJOR PROJECTS

Byron Neiles, Senior VP , Major Projects, Enbridge Inc.

Key Messages

• $31B portfolio represented by 35

projects

• $11B EEP portfolio represented by

11 projects

• Scalable workforce, strong supply

chain relationships

• Effective permitting approach
• Unwavering commitment to safety
• Proven track record

2

3

Major Projects – A Core Competency

Stats

• Staff – 1,600+
• Field – 10,000+
• Portfolio – $31B

New for 2014

• Line 3 Replacement
• Beckville Plant

President & CEO Al Monaco VP Offshore & Gas Execution Senior VP Major Projects Byron Neiles VP U.S. Liquids Execution VP CDN Liquids & Green Execution VP CDN Oil Sands Execution VP EPC and Project Services VP U.S. Liquids Execution

4

Project Development Expertise

• Well known corridors
• Comprehensive historic project and

market cost data

• Reliable cost estimating and

schedules

• Standardized designs
• Team of technical experts

5

Secured Supply Chain & Resources

Jan-10 Apr-10 Jul-10 Oct-10 Jan-11 Apr-11 Jul-11 Oct-11 Jan-12 Apr-12 Jul-12 Oct-12 Jan-13 Apr-13 Jul-13 Oct-13 Jan-14 Apr-14 US$ / Short Ton Pipe Enbridge Market

• Multi-year frame agreements
• Growing & diversifying

supply chains

• Scalable workforce
• Continuous organizational reviews

Enbridge Pipe vs. Market Pricing

6

Regulatory and Permitting Effectiveness

• Received 100% of permits applied

for since 2010

• Proactive stakeholder engagement
• Thorough and transparent land and

environmental reviews

• Emphasis on integrity & safety

1.50 0.84 1.28 1.04 1.00 0.0 0.5 1.0 1.5 2.0 2.5 3.0 2009 2010 2011 2012 2013 MP TRIF Frequency 3 Year Rolling Avg

7

Path to Zero Safety Culture

• 10,000+ temporary workforce
• Record field hours
• Significant focus on leading

indicators

• Prevention, training and

surveillance

• Aligning contractor and industry

safety performance

MP Historical Safety Performance

50%

8

Proven Execution Track Record

• Disciplined control: cost,

schedule and quality

• Rigorous risk identification

and mitigation

• Extensive governance

and reporting

• Repeatable execution
• Experienced teams

9

Eastern Access Phases 1 & 2

The Project:

• Line 6B 210 mile pipe replacement
• New pump stations, tankage and terminal

upgrades

• Line 62 Horsepower Expansion

Cost:

• $2.1 Billion*

In-service date:

• Range of ISDs 2013 – 2014

Status:

• 160 miles of Line 6B replacement is on target to begin line fill in April
• ROW and permitting for the remaining 50 mile replacement secured, construction to begin

this spring for Q3 2014 in service date

* Jointly funded 25% EEP / 75% ENB

10

U.S. Mainline Expansion

The Project:

• Ph. 1: Line 67 450 kbpd to 570 kbpd

Line 61 450 kbpd to 560 kbpd

• Ph. 2: Line 61 560 kbpd to 1,200 kbpd
• Ph. 3: Line 67 570 kbpd to 800 kbpd

Cost:

• U.S. Portion: $1.9 Billion*

In-service date:

• Range of ISDs 2014 - 2016

Status:

• Leveraged existing footprint
• Standard station design
• Secured construction permits; construction

underway

* Jointly funded 25% EEP / 75% ENB

11

Sandpiper

In-service date:

• 2016

Status:

• Right-of-Way acquisition ahead of plan

and currently at 50%

• Major Federal Permit Applications

completed and submitted to the US Army Corps of Engineers

The Project:

• Capacity 375 kbpd for 238 miles, 30” pipe
• Capacity 225 kbpd for 317 miles, 24” pipe
• Capacity 250 kbpd for 57 miles, 24” pipe
• 4 pump stations & 7 tanks

Cost:

• $2.6 Billion*

* Jointly funded 62.5% EEP / 37.5% Williston Basin Pipe Line LLC (a subsidiary of Marathon Petroleum Company)

12

Line 3 Replacement

The Project:

• Replace 1,031 miles of 34” pipeline

with 36” pipeline

Cost:

• U.S. Portion: $2.6 Billion*

In-service date:

• 2017

Status:

• Reassembled successful Alberta Clipper project team
• Securing supply chain
• Known corridor with established relationships

* Project to be jointly funded by ENB and EEP at participation levels to be finalized and approved by a Special Committee of the independent Board of Directors.

Beckville Plant

The Project:

• 150 MMcf/d Cryogenic Natural Gas

Processing Plant near Beckville, Texas

Cost:

• $0.1 Billion*

In-service date:

• 2015

* Project is funded by EEP and MEP based on their proportionate ownership in Midcoast Operating, which is currently 61% and 39%, respectively

13

Status:

• Key components procured early
• Construction contract awarded
• Construction permit authorized by Texas Commission on Environmental Quality

14

Key Takeaways

• Executing with confidence
• Dedicated, scalable

construction capability

• Rigorous controls and

governance

• Disciplined processes
• Majority of projects tracking
• n time and budget
• Proven track record

STRATEGIC OVERVIEW - MEP

Greg Harper, President, Gas Pipelines & Processing, Enbridge Inc. Principal Executive Officer, Midcoast Energy Partners, L.P .

2

Key Messages

Execute growth strategy

• First drop-down post-IPO expected mid-2014
• 100% debt-funded
• Deliver target distribution growth rate
• Secure new growth opportunities

Strengthen underlying business performance

• Deliver on actionable opportunities – optimization, enhanced market access,

and optionality

• Manage and pursue opportunities to reduce volume and commodity price

sensitivity

Vision: Become leading natural gas and NGL midstream infrastructure developer, operator and service provider

• Continue to provide ‘best in class’ gathering, processing & transportation

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

Corporate Structure

Corporate structure as of March 21, 2014

61% LP interest 46% LP interest 2% GP interest 52% LP interest 2% GP interest 16.3% LP interest (indirect)

Enbridge Inc. (NYSE: ENB) (Baa1 / A-) Enbridge Energy Partners, L.P. (NYSE: EEP) (Baa2 / BBB)

39% LP interest

Operating Subsidiaries

100% ownership interest

Midcoast Operating, L.P. “Midcoast Operating”

Texas Express NGL System Joint Venture

35% ownership interest 100% interest (indirect)

Midcoast Energy Partners, L.P. (NYSE: MEP) Public Unitholders

Enbridge Inc. owns ~21% of EEP

3

4

Attractive Investment Proposition

• 39% interest in Midcoast

Operating

• Remaining interest available for

drop-down ~$3 billion (2)

• Valuation to improve as we

execute on growth strategy

Investment Highlights

Atlas Pipeline Crestwood Regency Energy Midcoast DCP Midstream Targa Resources Markwest EnLink Summit Midstream QEP Midstream Western Gas Access Midstream

EQT Midstream S&P 500 Utilities S&P 500

10-Yr Treasury Notes

FTSE NA REIT 0% 1% 2% 3% 4% 5% 6% 7% 8% 9% 10%

Other Asset Classes (1)

Peer Group

Midstream MLP’s (1)

MEP: 6.1%

Peer Average: 5.3%

(1) Yield as of March 24, 2014 (2) Represents net book value of assets as of December 31, 2013.

• Large scale natural gas/NGL

midstream business positioned in key producing basins

• Offer integrated solutions

across the midstream value chain

MEP Business Overview

5

Enhanced Natural Gas & NGL Midstream Strategic Focus

Gas-Focused Operations Liquids-Focused Operations

“Pure-Play” Natural Gas & NGL Midstream

Enhances Strategic Focus of Partnership Increases Ability to Respond to Market Opportunities Enhanced Access to Capital MEP Growth Supported by Drop-Downs

Energy Partners, L.P.

6

Drop-Down of Natural Gas Business

IPO NTM 9/30/14 2017E

(1) Compounded annual distribution growth rate. Target annualized minimum quarterly distribution is $1.25/unit.

MEP EBITDA Growth Through….

Deliver Attractive Distribution Growth

100% 61% 39%

 MEP to Acquire 100% of Midcoast Operating within 5 years

• 1st Drop-down post-IPO targeted mid-2014 ~ $300 – $500 million

 Secure and execute on ~$1 billion capital growth program through 2017  Positioned for commodity price recovery

IPO 2014 2017e

Natural Gas business ownership

65% 62%

Enbridge Inc. (ENB)

• A-/Baa1
• $37 billion equity market capitalization

Enbridge Energy Partners, L.P. (EEP)

• BBB/Baa2
• $11 billion equity market capitalization

Support of Strong Sponsors:

 Financial Support and Risk Management  Operational Oversight and Management  Major Project Execution and Risk Mitigation  Commercial and Investment Review Oversight

Growth and Development Aligned and Supported by Sponsors

7

Note: Standard & Poor’s/Moody’s credit ratings respectively. Market capitalization as

• f March 3, 2014.

Energy Partners, L.P.

8

Lower 48 Natural Gas Production Forecast

Robust natural gas production outlook

50 60 70 80 90 100 110 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 BCF/day

Enbridge Jan 2014 PIRA Oct 2013 Wood MacKenzie Nov 2013 CERA Dec 2013 EIA Dec 2013

9

Natural Gas Demand Forecast

1,770 223 996 79 546 6 70 4 199 3 1,592 35 557 266 354 2,161 533 139 Coal retirements = 6,617 Industrial = 2,916 2013-2025 (mmcfd)

Source: Wood Mackenzie, November 2013

Midcoast assets located in single largest demand growth area

10

North American LNG Exports to Asia Increase Gas Demand

$4.30 $3.61 $0.10 $1.40 $3.00 $4.00 $0.46 $0.39 $2.50 $1.35 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00 $16.00 USGC ($10.36) BC ($10.75)

2016 LNG Exports to Asia

Shipping LNG Shrinkage (fuel) Liquefaction Pipeline Transport Gas price

Asian Contract Price ($13.43) $3.07 Netback

Source: Preliminary 2014 Enbridge Fundamentals View, PIRA

$2.68 US exports BC exports

2 4 6 8 10 12 14 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 Bcf/d

North American LNG Exports

East Texas asset footprint ideally positioned to access LNG export infrastructure

11

Strong Production Growth Drives Infrastructure Investment

5 10 15 20 25 30 35 40 45 20 40 60 80 100 120

2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 $ Billions Bcf/d

US Midstream Infrastructure Requirements

Base Case

Natural Gas / NGL / Crude Oil Rail & Marine Logistics Natural Gas & NGL Processing Natural Gas Gathering, Pipelines & Storage Natural Gas Production

Sources: “Oil & Natural Gas Transportation & Storage Infrastructure: Status, Trends, & Economic Benefits,” IHS, December 2013

Sustained growth opportunities for natural gas infrastructure investment

12

North American Production Growth Evolving

Growing northeast production is restructuring the gas markets and enabling exports

1.0 2.1 1.2 0.8 (0.5) (0.3)

Red = Decrease Blue = Increase

Change in flows between 2013 and 2018

WCSB Rockies Mid Continent Permian GoM Offshore Gulf Coast Appalachia

0.5 1.7

Only Flows > 0.3 Bcf/d shown LNG Exports

2.8 1.5

MX Exports

1.6 0.4 0.5 (0.5) 0.6

LNG Exports

(0.5) 1.1

Source: Preliminary 2014 Enbridge Fundamentals View

0.7

13

Large-Scale, Diversified Business

Anadarko System Texas Express NGL System North Texas System East Texas System

Petal

Logistics and Marketing

EAGLEBINE

Assets well positioned to pursue opportunities in emerging growth basins

Key Assets

Natural Gas Deliveries ~ 2.5 bcf/d Gathering and Transportation Pipelines 11,400 miles Processing Capacity (26 plants) 2.3 Bcf/d Treating Capacity (11 plants) 1.3 Bcf/d Texas Express NGL system 35% JV interest CLINE SHALE

14

Growth Outlook

• Secure and execute on growth opportunities
• Leverage existing asset base and pursue step-outs in close proximity
• Expand processing capabilities
• Pursue accretive acquisitions
• Complement and diversify existing asset footprint ~ value chain integration
• Longer-term: geographic diversification (i.e. Bakken, Eagle Ford, West Texas,

Oklahoma)

• Shifting North American supply and demand

fundamentals present new opportunities for pipeline infrastructure

15

Strategic Priorities

• First drop-down post-IPO expected mid-2014
• Position for future drop-downs
• Aggressively pursue and secure organic growth
• Enhance value-added services to increase competitiveness of existing supplies
• Pursue new business opportunities with low-risk commercial framework
• Rationalize existing portfolio
• System enhancement and optimization
• Redeploy assets to capture new opportunities and enhance returns
• Utilize Logistics & Marketing to attract new business to

G&P footprint

• Leverage first-mover capabilities in greenfield plays leading to infrastructure

development

• Transition from optimizer to true commercial developer
• Manage costs

16

Key Takeaways

• Deliver target distribution growth
• First drop-down post-IPO expected mid-2014
• Pursue and secure organic growth
• Strengthen underlying business performance
• Manage and pursue new opportunities
• Reduce volume and commodity price sensitivity
• Deliver more certain and stable cash flows
• Strong natural gas fundamentals backdrop supports

continued infrastructure investment

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

NATURAL GAS

Terrance McGill, President , Midcoast Energy Partners

Key Messages

2

• Enhance the profitability of our existing assets
• Leverage our large and strategically located asset base

to pursue attractive organic growth opportunities

• Enhanced access to capital positions business to

respond to market opportunities

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

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

3

Rich Gas Continues to Drive Production in our Regions

NGL and crude oil value will continue to incentivize producers to drill

Forward prices as of March 14, 2014.

$- $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 $14.00

East Texas East Texas Cotton Valley Anadarko Granite Wash North Texas Marble Falls

$/MMcf

Illustrative Production Value

Natural Gas NGLs Condensate

~$4.25 ~$6.17 ~$11.96 ~12.93

Nymex = $4.25

4

Supply Growth Driven by Liquids Plays

Pursue rich gas opportunities and basin diversification

2 4 6 8 10 2012 2014 2016 2018 2020 2022 2024 Annual Average (Bcf/d)

Barnett Production Forecast

3rd Party Range 2 4 6 8 10 2012 2014 2016 2018 2020 2022 2024 Annual Average (Bcf/d)

Haynesville Production Forecast

3rd Party Range 2 4 6 8 10 2012 2014 2016 2018 2020 2022 2024 Annual Average (Bcf/d)

Anadarko Production Forecast

3rd Party Range 5 10 15 20 25 30 2012 2014 2016 2018 2020 2022 2024 Annual Average (Bcf/d) 3rd Party Range 2 4 6 8 10 2012 2014 2016 2018 2020 2022 2024 Annual Average (Bcf/d)

Eagle Ford Production Forecast

3rd Party Range 2 4 6 8 10 2012 2014 2016 2018 2020 2022 2024 Annual Average (Bcf/d)

Bakken Production Forecast

3rd Party Range

Marcellus/Utica Production Forecast

5

NGL Production Growth

Source: PIRA “Global NGL Markets and the Growing Role of North America” (Oct 10, 2013)

Strong NGL supply outlook supports continued infrastructure and services growth

6

NGL Demand Outlook

Improving NGL price outlook as exports complement domestic demand

Source: Petral Annual Forecast, August 2013 100 200 300 400 500 600 2010 2015 2020 2025 MB/D

Natural Gasoline

exports

• misc. markets

ethylene feedstocks ethanol denaturant crude blending gasoline blenders refinery inputs 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2010 2015 2020 2025 MB/D

Ethane

exports ethylene feedstock 50 100 150 200 250 300 350 400 450 500 2010 2015 2020 2025 MB/D

Butane

exports

• misc. markets

transfers to private storage

• ther chemical

ethylene feedstock Dehydro MTBE merchant isom units

500 1,000 1,500 2,000 2010 2015 2020 2025 MB/D

Propane

exports ethylene feedstock industrial and other markets refinery propylene to chem propane dehydro motor fuel

7

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 Marble Falls Associated Rich Gas 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 100,000+ Bpd of long-term fractionation capacity secured

CLINE SHALE EAGLEBINE

8

Rig Counts Holding Steady

Petal

Recent permitting uptick across asset footprint

50 100 150 200 250 300 350 MAR 22 APR 12 MAY 03 MAY 24 JUN 14 JUL 05 JUL 26 AUG 16 SEP 06 SEP 27 OCT 18 NOV 08 NOV 29 DEC 20 JAN 10 JAN 31 FEB 21 MAR 14

Fort Worth Basin Rig Count, 52-Weeks (RigData)

Rigs Well Starts Permits

• 20

40 60 80 100 120 140 160 MAR 22 APR 12 MAY 03 MAY 24 JUN 14 JUL 05 JUL 26 AUG 16 SEP 06 SEP 27 OCT 18 NOV 08 NOV 29 DEC 20 JAN 10 JAN 31 FEB 21 MAR 14

Anadarko 6-County Rig Count, 52-Weeks (RigData)

Rigs Well Starts Permits

9

Anadarko System – Strategically Located in Texas Panhandle and Western Oklahoma

Premier position in rich gas basin

Processing Plant Treater Plant Gas Pipeline Liquids Pipeline Texas Express

(1) Source: RigData. Rig count as of week of March 7, 2014. (2) As of February 28, 2014. (3) As of June 30, 2013. (4) Includes three standby processing plants.

Cline Shale Mississippi Lime

Highlights Active rigs 53 rigs(1) Rigs drilling on dedicated acreage 18 rigs(2) Miles of natural gas gathering and transporting pipelines ~2,950 miles Wells connected to delivery receipt points on system ~3,600 wells(3) Processing plants 12 plants(4) Processing capacity 1,115 MMcf/d

10

East Texas System – Extensive Footprint in East Texas: Haynesville & Cotton Valley

Strategically positioned to expand footprint into emerging basins

East Texas Basin Haynesville Shale Cotton Valley Eaglebine

(1) Source: RigData. Rig count as of week of March 7, 2014. (2) As of February 28, 2014. (3) Includes two HCDP plants. Includes Beckville plant, which is under construction and is expected to commence service in early 2015. (4) Includes one standby treating plant.

Processing Plant Treater Plant Gas Pipeline Liquids Pipeline

Highlights Active rigs 58 rigs(1) Rigs drilling on dedicated acreage 21 rigs(2) Miles of natural gas gathering and transporting pipelines ~3,850 miles Wells connected to delivery receipt points on system ~5,600 wells Processing plants 7 plants(3) Processing capacity 885 MMcf/d(3) Treating plants 11 plants(4) Treating capacity 1.3 Bcf/d(4) Fractionation facilities 1 facility Fractionation capacity ~3,000 Bpd

11

North Texas System – Extensive Asset Footprint

Established operator; positioned to secure growth opportunities

(1) Source: RigData. Rig count as of week of March 7, 2014. (2) As of February 28, 2014. (3) As of June 30, 2013. (4) Includes one standby processing plant.

Processing Plant Gas Pipeline Liquids Pipeline Texas Express

Highlights

Active rigs 42 rigs(1) Rigs drilling on dedicated acreage 4 rigs(2) Miles of natural gas gathering and transporting pipelines 4,600 miles Wells connected to delivery receipt points

• n system

~3,400 wells (2,258 receipt points) (3) Processing plants 7 plants(4) Processing capacity 275 MMcf/d(4) Stabilizers 1 stabilizer Stabilizer capacity 4,000 Bpd

Barnett Dry Gas Barnett Rich Gas Barnett Oil Marble Falls

12

Texas Express NGL System

• NGL Mainline System
• JV with Enterprise Products Partners (35%, operator),

Midcoast Operating (35%), Anadarko Petroleum Corporation (20%) and DCP Midstream (10%)

• 580-mile, 20-inch NGL pipeline originates from

Skellytown, TX to Mont Belvieu NGL hub

• Initial capacity of ~280,000 Bpd; expandable to

~400,000 Bpd

• NGL Gathering Systems
• JV with Enterprise (45%), Midcoast Operating (35%,
• perator) and Anadarko (20%)
• Addresses Mid-Continent, Rockies and West Texas NGL

constraints

• Enhances our competitive position by providing greater

access to Mont Belvieu fractionation

Strategic Benefits Description of Assets Texas Express Footprint

New NGL Gathering

Texas Express Mainline Gathering Pipelines Under Construction Proposed Gathering Pipelines

Dallas Mont Belvieu Houston Skellytown

Participation in NGL value chain - secures long-term demand-based cash flows

• 50,000

100,000 150,000 200,000 2014E 2105E 2016E 2017E Midcoast All Other Shippers

Mainline System Volume Commitments

13

Understanding Volume Trends

• Substituting rich gas for dry gas
• Producers drilling wells, delaying completions
• 2,000

4,000 6,000 8,000 10,000 1 6 11 16 21 26 31 36 41 46 51 56 Type Curve (Mcf/d) Month Cotton Valley Haynesville

• 200

400 600 800 1,000 1,200 1,400 1 6 11 16 21 26 31 36 41 46 51 56 Type Curve (Mcf/d) Month Marble Falls Barnett

• 2,000

4,000 6,000 8,000 10,000 1 6 11 16 21 26 31 36 41 46 51 56 Type Curve (Mcf/d) Month Granite Wash Hogshooter

Illustrative Production Values

14

Business Opportunities: Gathering, Processing & Transportation

EAGLEBINE CLINE SHALE

Leverage existing capabilities to increase reach both inside and outside of current asset footprint

COTTON VALLEY

Actionable Growth Opportunities

• Capture rich gas opportunities
• New pipeline laterals, NGL laterals, and

compression projects

• Expand processing capabilities

System Optimization

• Maximize throughput and NGL

production

• Ramp-up of Texas Express and Ajax
• Plant upgrades
• System capabilities enhance
• perational flexibility and reliability
• Daily dispatch to route rich gas to most

efficient plants

15

Business Opportunities: Logistics & Marketing

Transform Logistics & Marketing from optimizer to true commercial developer

TexPan Rail

Growth Oriented Value Added Midstream Solutions

• Expand takeaway solutions for customers
• Bundled service offerings
• Access premium markets to enhance customer netback
• Leverage “first-mover” advantage capabilities in emerging basins

16

Organic Projects Support Distribution Growth

Expected Timing Description Cost

(1) Represents MEP’s 35% interest in the Texas Express NGL System joint venture.

Beckville Plant

In-service in early 2015

• Provide processing to rich Cotton Valley gas
• Capacity of ~150 MMcf/d and 8,500 Bpd of

NGLs

• Ramp-up throughout 2015; 2016 the first full

year of contribution ~$145 million

Ajax Plant

• 150 MMcf/d cryogenic processing plant with

a ~2,000 Bpd condensate stabilizer

• Ramp-up through early 2014; 2015 the first

full year of contribution In-service in Q3 2013 $230 million

Texas Express

• NGL Mainline: 580-mile, 280,000 bpd NGL

pipeline from Skellytown, TX to Mont Belvieu; 10 year ship-or-pay contracts with 5 year dedication

• Gathering: 116 miles of pipeline
• Full ramp-up expected over time

In-service in Q4 2013 $400 million (1) Incremental Growth 2014 2015 2016 2017

Unsecured Growth Projects

2014 and beyond

• Extend asset reach into Eaglebine and Cline
• Plant upgrades
• Compression projects
• NGL injection terminals and NGL pipelines
• Expand condensate and liquids handling and

takeaway

• Small-scale acquisitions

~$250 million/yr

17

Safety and Operational Reliability

Industry leader in integrity management

• Comprehensive Integrity Management Program
• Increased line patrols, in-line inspections and incident response

capabilities

• Control center enhancements
• Installation of EFRD (emergency flow restricting devices) to protect

HCAs on liquids and gas transmission lines

• Implementation of industry leading best practices
• Strengthened the safety culture

18

Key Takeaways

• Enhance the profitability of our existing assets
• Enhance value of first and prospective drop-downs
• Leverage our large and strategically located asset base

to pursue attractive organic growth opportunities

• Enhanced access to capital positions business to

respond to market opportunities

• Attractive entry point in commodity price cycle

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

FINANCE – EEP

Steve Neyland, Vice President, Finance

2

Key Messages

• Long term value proposition
• Attractive yield combined with significant tax deferral
• Sustainable distribution
• Strong investment grade credit rating
• Secured Liquids projects collectively further

transform the Partnership to lower risk business model

• Distribution coverage strengthens as projects enter service
• Manageable funding outlook and growing

financial strength

• Targeting 2% to 5% annual distribution growth
• Attractive long-term growth outlook
• Bolstered by asset drop-down potential by General Partner

3

Delivering Prudent Growth - Liquids

($MM) Capital Cost Net Capital EEP Target In-Service EBITDA multiple (4) Risk Profile Bakken Growth Projects Sandpiper (1) 2,600 1,625 early 2016 7x Long-term Ship-or-Pay/Cost of

Service

Eastern Access (1)

30 year Cost of Service Highly certain cash flows No volume risk No capital risk (2)

Line 5, Line 62 expansion Line 6B Replacement 2,100 525 In-Service 2013 2Q14 – 3Q14 9x Line 6B Expansion + tankage 400 100 early 2016 8x US Mainline Expansion (1) Line 67 (Border to Superior) (3) Line 61 (Superior to Flanagan) 1,900 475 Phase 1 3Q14; Phase 2 2015- 2016 5x Chicago Connectivity (Line 62 twin) 500 125 2H 2015 8x Line 3 Replacement (1) 2,600 1,300 2H 2017 8x $10,100 $4,150

Attractive suite of low risk, fee-based organic growth secured

(1) Eastern Access, Mainline Expansion projects and Line 3 Replacement 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) Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions. (4) Represents first full year EBITDA contribution.

4

Risk Profile – Lower Risk Business Model

Unconsolidated View

32% 27% 18%

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 commodities length (before hedging). Contribution is based on revenues from Liquids segment and gross margin from Natural Gas segment, excluding non-controlling interest.

2008 2013 2017e 2015e

Capital Forecast and Liquidity Position

Net Capital Forecast (2014- 2017) *

* Liquids capital expenditure forecast is net of the Joint Funding Agreements with Enbridge Inc. and Marathon Petroleum

• Corporation. Natural Gas capital expenditures net of funding with Midcoast Energy Partners, L.P.

5

3.2 0.3 0.4

$0 $1,000 $2,000 $3,000 $4,000 $5,000

2014e - 2017e

Maintenance capital Natural Gas Integrity capital and other growth Liquids secured growth

1.2 $ millions

2,463 165

$0 $500 $1,000 $1,500 $2,000 $2,500 $3,000 Available Liquidity

Credit Facilities Cash

Liquidity Position 12/31/2013

$ millions

$2,628

Manageable capital expenditures outlook complemented by strong liquidity position

• $3.175 billion Committed Credit Facilities
• $1.5 billion Commercial Paper Program

Net of Joint Funding

~ $5.1 billion

6

Joint Funding Agreements

Eastern Access and US Mainline Expansions

• Enbridge Inc. to fund 75% of projects ~ in form of 100% equity

investment

• EEP has separate options to upsize interest by up to 15% one

year from last in-service date

Line 3 Replacement

• Project to be jointly funded with Enbridge Inc.*

Sandpiper

• Marathon Petroleum Corp. will fund 37.5% of Project

Sandpiper construction costs. **

Joint funding enhances Partnership’s financing flexibility

Enbridge Inc. Joint Funding Marathon Petroleum Corp. Joint Funding

$1,225 $3,675 $1,300 $1,300 $1,625 $975

EEP Funded ENB Funded MPC Funded

Sandpiper

Line 3 Replacement Eastern Access $ millions

Net Capital To EEP $4,150

Mainline Expansions

*Assumed 50% joint funding participation levels to be finalized by a Special Committee of the independent Board of Directors. **Marathon Petroleum Corp. will fund 37.5% of Project Sandpiper cost and assume a ~27% equity interest in the EEP North Dakota system, once the project enters service.

2014 EBITDA Guidance (unconsolidated)

1,055 1,300 88 250 $0 $1,000

2013 2014e

Noncontrolling Interest*

Strengthening results supported by strong fundamentals & market access projects cash flows

* Noncontrolling interest attributable to projects jointly funded with Enbridge Inc. Also includes noncontrolling interest attributable to Midcoast Energy

• Partners. L.P.

7

$ millions

2014 EBITDA Growth:

• Lakehead

+ ~$110MM

• North Dakota

+ ~$95MM

• Eastern Access

+ ~$35MM

• Mainline Expansions + ~$5MM

 Strong supply & demand

• utlook

 Full year 2013 projects  2014 projects in-service

EBITDA Growth Outlook (unconsolidated)

1,055 1,300 88 250 $0 $1,000 $2,000 $3,000

2013 2014e 2015e 2016e 2017e

Noncontrolling Interest*

EBITDA growth underpinned by projects with low risk commercial framework

* Noncontrolling interest attributable to projects jointly funded with Enbridge Inc. and Marathon Petroleum Corp. equity interest in EEP North Dakota System. Also includes noncontrolling interest attributable to Midcoast Energy Partners. L.P.

8

$ millions  Eastern Access  Mainline Exp  Sandpiper  Eastern Access  Mainline Exp  Sandpiper FY  Eastern Access  Mainline Exp  L3R  Eastern Access  Mainline Exp  North Dakota FY

Visible Cash Flow Growth

9

Strengthening Distribution Coverage

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

Coverage*

* 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

10

Operational Reliability

$0 $100 $200 $300 $400 $500 $600 2008 2009 2010 2011 2012 2013 2014e 2015e 2016e 2017e $ million

* Integrity capital expenditures do not include Line 6B replacement and planned Line 3 replacement program. New or modified requirements could impact our future integrity costs.

Liquids Integrity Capital Expenditures:

• Sleeving pipeline segment
• Cut-out & replace pipeline segment
• Recoating pipeline segment

Recoverability:

• Engage shipper group annually to

recover a portion of integrity capital through toll structure Liquids Integrity Capital*

11

Funding Plan 2014-2017 (unconsolidated)

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.

12

Growing Financial Strength

Strengthening credit metrics as expansion projects begin to generate cash

Will maintain strong investment grade credit profile (BBB/Baa2)

Actuals

3.0 3.5 4.0 4.5 5.0 5.5 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Target <4.0 times

Actuals

2.0 3.0 4.0 5.0 6.0 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017

Target >4.0 times Actuals

Debt /EBITDA FFO / Interest

Credit metrics post-2009 normalized for Lines 6A and 6B remediation costs and insurance recoveries.

13

Maturity Outlook

Prudent term debt management

Available Maturity Windows

14

Distribution Growth Target

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 +

2017e

Distributable Cash         

15

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

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

~ $10B

($ Billions)

Examples:

Key Takeaways

• Secured Liquids growth projects collectively further transform

the Partnership to an even lower risk business model

• Visible distributable cash flow growth as projects enter

service – strengthening coverage

• Manageable funding plan and growing financial strength
• Distribution growth: targeting 2% to 5% annual growth
• Maintain strong investment grade credit rating
• Strong, strategically aligned, supportive General Partner

Enbridge Inc.

• Attractive long-term growth outlook

16

17

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

200 400 600 800 1,000 1,200 1,400 1,600

Adjusted EBITDA* Adjusted Operating Income Depreciation**

$ millions

Guidance Range $ per unit

Distribution Growth

500 1,000 1,500

2011 2012 2013 2014e

$ millions

Liquids Projects Deliver EBITDA Growth

Based on adjusted EBITDA.

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

2007 2008 2009 2010 2011 2012 2013 2017e

2% - 5% Annual Growth Target 2.7% 4.2%

• 3.8%

3.6% 2.1%

FINANCE – MEP

Steve Neyland, Vice President, Finance

Key Messages

19

Large Scale, Diversified Business Strong Sponsor and Management

Strong Sponsor and Management Strategically Positioned Asset Base Large Scale, Diversified Business Enhanced Access to Capital Predictable Distribution Growth

• Execute growth strategy and deliver

target distribution growth rate

– Mid-teens annual distribution growth

• First drop-down post IPO mid-2014

– 100% debt financed – Position for future drop-downs

• Target conservative capital structure
• Financial support from sponsor

enhances flexibility

• Disciplined risk management

program to stabilize earnings and cash flows

20

Execute Growth Program

IPO NTM 9/30/14 2017E

(1) Compounded annual distribution growth rate. Target annualized minimum quarterly distribution is $1.25/unit.

MEP EBITDA Growth Through…. Deliver Attractive Distribution Growth

100% 61% 39%

 MEP to Acquire 100% of Midcoast Operating within 5 years

• 1st Drop-down post-IPO targeted mid-2014
• ~ $300 – $500 million
• Secure and execute on ~$1 billion capital growth program through 2017

IPO 2014 2017e

Natural Gas business ownership

Enhanced Access to Capital

Targeting Conservative Capital Structure

• Enhanced access to capital improves ability to respond to

business opportunities

• Targeting credit metrics consistent with investment grade

midstream companies: target Debt/EBITDA < 3.0x

• 1.2x Debt/EBITDA at IPO*
• Approximately $515 million of available liquidity

for drop-down or investments

• Execute 100% debt funded first drop-down
• Leverage financial support from sponsors
• Secure term debt

*Midcoast Operating and MEP are co-borrowers under the credit facility. Leverage metric calculation per the Credit Agreement: Debt at MEP / Midcoast Operating EBITDA

335

515

200 400 600 800 1,000 12/31/2013

$ millions $850 MM Credit Facility

Available Credit

21

Financing Plan and Leverage Outlook

0.5 1 1.5 2 2.5 3 3.5 4 4.5 5 5.5 6

IPO 1st Drop-Down

Leverage Outlook Target Leverage: < 3.0x

• First drop-down post IPO ~ flexibility

to fund 100% debt

• Secure term debt
• Position for subsequent drop-downs
• Long-term funding approach:
• 50% Debt
• 50% Equity

Debt to EBITDA = MEP Debt MOLP EBITDA

Financing Plan

Midcoast Operating and MEP are co-borrowers under the credit facility. Leverage metric calculation per the Credit Agreement: Debt at MEP / Midcoast Operating EBITDA .

22

Covenant Covenant acquisition period

23

Organic Projects Support Distribution Growth

Expected Timing Description Cost

(1) Represents MEP’s 35% interest in the Texas Express NGL System joint venture.

Beckville Plant

In-service in early 2015

• Provide processing to rich Cotton Valley gas
• Capacity of ~150 MMcf/d and 8,500 Bpd of

NGLs

• Ramp-up throughout 2015; 2016 the first full

year of contribution ~$145 million

Ajax Plant

• 150 MMcf/d cryogenic processing plant with

a ~2,000 Bpd condensate stabilizer

• Ramp-up through early 2014; 2015 the first

full year of contribution In-service in Q3 2013 $230 million

Texas Express

• NGL Mainline: 580-mile, 280,000 bpd NGL

pipeline from Skellytown, TX to Mont Belvieu; 10 year ship-or-pay contracts with 5 year dedication

• Gathering: 116 miles of pipeline
• Full ramp-up expected over time

In-service in Q4 2013 $400 million (1) Incremental Growth 2014 2015 2016 2017

Unsecured Growth Projects

2014 and beyond

• Extend asset reach into Eaglebine and Cline
• Plant upgrades
• Compression projects
• NGL injection terminals and NGL pipelines
• Expand condensate and liquids handling and

takeaway

• Small-scale acquisitions

~$250 million/yr

Risk Profile – Disciplined Hedging Program

Creditworthy Counterparties

(A3 / A-) (Baa1 / BBB+) (Aaa / AAA) (A3 / A-) (Baa2 / BBB)

Contract Mix by System

Risk Profile (before hedging) (1)

Fee-Based 45% Commodity 55%

Risk Profile (after hedging) (1)

Fee-Based 45% Commodity 20% Hedged 35%

(1) Risk Profile based on forecasted gross margin for 12 month period ended 12/31/2014 for Gathering,

Processing & Transportation segment; includes equity earnings from joint venture investment in Texas Express NGL system.

• Hedging targets:
• 70% hedged in year 1
• 50% hedged in year 2
• Requires Midcoast Operating to hedge on a rolling

quarterly basis

• Financials not used for speculative purposes

Hedging Policy

24

0% 20% 40% 60% 80% 100%

Anadarko System East Texas System North Texas System Texas Express NGL System

30% 60% 30% 100% 70% 40% 70% Commodity Fee-Based

25

Commodity Positions and Gross Margin Sensitivities – Midcoast Operating

MOLP - NGL and Crude Price Fluctuations2 MOLP - Natural Gas Price Fluctuations2

(100) (50)

• 50

100 2014 2015 $ in millions Prices: -20% Prices: +20%

(1) Represents Estimated Commodity Positions for the Gathering, Processing and Transportation Segment of Midcoast Operating, L.P. Unaudited, $ in millions. Options valued at their strike prices to determine hedged cash flows. (2) Sensitivities of +/- 20% were applied to forward market prices at 1/31/2014.

(50) (25)

• 25

50 2014 2015 $ in millions Prices: -20% Prices: +20%

Hedge Weighted Avg Value % Hedge Price $ MM Natural Gas 11,781 MMbtu/d 81% 9,500 MMbtu/d $3.95 /MMbtu $13.7 C2 5,114 bpd

• bpd

$0.00 /gallon $0.0 C3 6,480 bpd 60% 3,900 bpd $0.93 /gallon $55.7 iC4 1,422 bpd 25% 350 bpd $1.64 /gallon $8.8 C4 2,163 bpd 57% 1,225 bpd $1.53 /gallon $28.7 C5 1,295 bpd 78% 1,008 bpd $1.90 /gallon $29.4 Total NGLs 16,474 bpd 39% 6,483 bpd $122.6 Condensate 3,316 bpd 73% 2,430 bpd $89.88/barrel $79.7 Hedged Commodity Gross Margin $216.0

Midcoast Operating (MOLP)

Volume Physical Hedged

2014 Estimated Commodity Positions & Hedged Cash Flows1

Commodity Price Assumptions

(1) NGL prices all based on Mont Belvieu pricing; average third party forecast as of January 2014 . (2) PIRA's Oil Market Forecasts, Feb. 6, 2014.

26

$60 $80 $100 $120 2014e 2015e 2016e 2017e WTI Crude ($/Bbl)

WTI Crude Oil

Internal Forecast PIRA Forecast $0.50 $0.60 $0.70 $0.80 $0.90 $1.00 $1.10 $1.20 2014e 2015e 2016e 2017e NGL Composite ($/gal)

NGL Composite Price (1)

Internal Forecast Average 3rd Party Forecast

(2)

2014e 2015e 2016e 2017e NYMEX Henry Hub Gas ($/MMbtu) $ 3.97 $ 4.41 $ 4.33 $ 4.58 NYMEX WTI Crude ($/bbl) $ 96.87 $ 92.30 $ 95.69 $ 99.53 NGLs Pricing ($/gal) Purity Ethane (C2) $ 0.34 $ 0.39 $ 0.47 $ 0.58 Propane (C3) $ 1.06 $ 1.04 $ 1.14 $ 1.24 Isobutane (iC4) $ 1.68 $ 1.68 $ 1.74 $ 1.80 Normal butane (nC4) $ 1.57 $ 1.57 $ 1.64 $ 1.70 Natural gasoline (C5+) $ 1.98 $ 2.05 $ 2.14 $ 2.23

Financial Support from Sponsors

Financial Support Agreement Working Capital Agreement

Purpose Derivative contracts, natural gas purchasing agreement and NGL purchase agreement support Working capital financing Borrower Midcoast Operating, L.P. Lender(s) Enbridge Energy Partners, L.P. (“EEP”), EEP subsidiary or EEP affiliate Amount Up to $700 million $250 million revolving Pricing 250 bps annual fee 1-month Libor + 250 bps Maturity The earlier of: (1) four years following closing; and (2) the date EEP owns less than 20% of Midcoast Operating Security Unsecured Termination Provision At Midcoast Operating’s option

Financial support from sponsor enhances ability to do business

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Key Takeaways

• Execute growth strategy and deliver target distribution growth rate
• Mid-teens annual distribution growth
• First drop-down post IPO mid 2014
• 100% debt financed
• Position for future drop-downs
• Target conservative capital structure
• Financial support from sponsor enhances flexibility
• Disciplined risk management program to stabilize earnings and

cash flows

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Financial Outlook 2014

Midcoast Operating, LP 2014e Adjusted EBITDA* $235 - $265 Depreciation $140 – $150 Operating Assumptions Natural Gas Volumes (MMbtu/d) Anadarko 850 - 900 East Texas 1,100 – 1,200 North Texas 300 - 320 2,250 – 2,420 NGL Production (Bpd) 88,000 – 92,000 Adjusted EBITDA* $105 – $125 Distributable Cash $75 – $95

Midcoast Energy Partners (MEP)

29

2014 Capital Expenditures1 Beckville Gas Processing Plant $110 Well Connect Expansion Capital 50 Texas Express NGL System 20 Expansion Capital 140 Maintenance Capital 65 Total Capital $385

Adjusted EBITDA includes equity earnings from joint venture investment in Texas Express NGL system

1Represents Capital Expenditure forecast at Midcoast Operating L.P. level. Capex to be proportionally shared between EEP and MEP based on ownership interest in Midcoast

Operating (MOLP).

CLOSING REMARKS

Mark Maki, President , EEP and Greg Harper, Principal Executive Officer, MEP

Key Takeaways

Safety, Operational Reliability and Execution are top priorities Enbridge Energy Partners (EEP)

• Strategic position supported by strong business fundamentals
• Secured growth projects collectively further transform the

Partnership to even lower risk business model Midcoast Energy Partners (MEP)

• Deliver target distribution growth
• Strong natural gas fundamentals backdrop supports

continued infrastructure investment opportunities EEP & MEP: Attractive long-term growth outlook