Enbridge Energy Partners, L.P. and Midcoast Energy Partners, L.P. - - PowerPoint PPT Presentation

enbridgepartners.com

Enbridge Energy Partners, L.P. and Midcoast Energy Partners, L.P.

Investment Community Presentation

January 2015

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Legal Notice

This presentation includes forward-looking statements and projections, which are statements that do not relate strictly to historical or current facts. These statements frequently use the following words, variations thereon or comparable terminology: “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “should,” “strategy,” “target”, “will” and similar words. Although the Partnership believes 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 Partnership’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) the Partnership’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 the Partnership’s facilities or refineries, petrochemical plants, utilities or other businesses for which the Partnership transports products or to whom the Partnership 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 the Partnership’s tariff rates; and (7) changes in laws or regulations to which the Partnership is subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance. Forward-looking statements regarding “drop-down” growth opportunities are further qualified by the fact that Enbridge Inc. is under no obligation to offer to sell us interests in its U.S. projects, and we are under no obligation to buy any such interests. Similarly, any forward-looking statements regarding potential “drop-down” transactions of interests in Midcoast Operating to Midcoast Energy Partners are further qualified by the fact that we are under no obligation to sell to Midcoast Energy Partners any such interests, and Midcoast Energy Partners is under no obligation to buy any such interests. As a result, we do not know when or if any such transactions will occur. The Partnership’s forward looking statements are 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 the U.S. securities regulators. The effect of any one risk, uncertainty

• r factor on any particular forward looking statement is not determinable with certainty as these are independent and our future course
• f action depends on management’s assessment of all information available at the relevant time. Except to the extent required by law,

we assume no obligation to publicly update or revise any forward looking statements, whether as a result of new information, future events or otherwise. Reference should also be made to the Partnership’s filings with the U.S. Securities and Exchange Commission (the “SEC”), including its Annual Report on Form 10-K for the most recently completed fiscal year and its subsequently filed Quarterly Reports on Form 10-Q, for additional factors that may affect results. These filings are available to the public over the Internet at the SEC’s web site (www.sec.gov) and at the Partnership’s web site.

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Investment Proposition

Strong Business Fundamentals: Strength & Stability

Migrating to a Much Lower Risk Business Model Strong General Partner Stable Distributions & Prudent Growth Attractive Yield

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Investment Highlights

 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

Total Shareholder Return

1991 2014

Enterprise Value - Large-Cap MLP Commercially secured

• rganic growth

underway

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

Low-risk transformative growth underway

Highlights 2014 Highlights

$0 $20,000 $40,000 $60,000 $80,000 $100,000 $120,000 $140,000

 Delivered 41% total shareholder return; increased distribution 4.9%  ~$2.3 billion of growth capital placed in service  Equity restructure to reset IDRs and establish single tier IDR structure  Completed $1 billion drop-down acquisition from ENB  ENB is reviewing potential restructuring plan to drop-down its U.S. liquids pipeline assets to EEP (1)

*Enterprise Value as of 1/21/15; **Return CAGR since inception to 12/31/2014 (nominal) (1) On December 3, 2014, Enbridge Inc. ("Enbridge" or "ENB") announced it is reviewing a potential restructuring plan that would involve the transfer of its directly held U.S. liquids pipeline assets to Enbridge Energy Partners, L.P., a U.S. affiliate of Enbridge. This review is underway and has not progressed to a conclusion.

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65% 62%

• Owner and operator of largest crude
• il pipeline system
• ~$41 billion equity market cap
• Strong investment grade (A-, Baa1)
• Proven track record: industry leading

EPS and DPS growth

• 19% 10-year TSR CAGR
• 12% 10-year DPS CAGR
• 33% dividend increase in 2015
• 14%-16% DPS growth forecast 2015-2018
• Strategy aligned with Partnership
• ~$44 billion organic growth program

underway

Strength of GP – Enbridge Inc.

Strength of GP – Enbridge Inc.

ENB: North American leader in energy delivery

Note: Standard & Poor’s/Moody’s credit ratings respectively. Market capitalization as of January 21, 2015.

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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)

High quality customer base ENB and EEP Strategically Aligned

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WCSB Supply Forecast vs. Pipeline Takeaway Capacity*

OTHER

ENB

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 MMb/d

2014 Enbridge Forecast Optimal Pipeline Capacity Supply Forecast

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

Keystone XL ENB Northern Gateway TransMountain Expansion Energy East

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Range of External Forecasts

500 1,000 1,500 2,000 2,500

Kbpd High Case Low Case

3rd Party Pipes Local Refining Enbridge - Bakken 3rd-Party Proposed Enbridge - Sandpiper

Bakken Crude Supply and Pipeline Takeaway Capacity

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Organic Growth Projects:

 Commercially secured  Low risk framework  Long-term contracts

Market Access Well Advanced

Incremental Market Access by 2017: +1.0MMbpd of Heavy; +0.7MMbpd of Light

Eastern Access Western USGC Access Light Oil Market Access

+50 kbpd +80 kbpd +250 kbpd +50 kbpd +600 kbpd +250 kbpd +300 kbpd

Light Heavy

+50 kbpd

Three major initiatives provide 1.7 MMbpd

• f increased market access and diversification

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Project Execution – 2014 In-Service

Eastern Access: Ln 6B Replacement  160 miles of Line 6B replacement entered service in May 2014  Remaining 50 mile replacement entered service October 2014

• ~$2.1 billion capital

Mainline Expansions  Line 61- expansion from 400kbpd to 560kbpd between Superior and Flanagan entered service August 2014

• ~$0.2 billion capital

Commercially Secured 30 year Cost of Service

* Jointly funded 25% EEP / 75% ENB

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Bakken Expansion – Sandpiper Pipeline

Clearbrook Superior Sarnia Chicago Patoka Toledo Montreal Westover Hardisty

Cushing

Regina Gretna

• Scope: 610 mile, 24”/30” pipeline
• Capacity: ~ 225 kbpd/375 kbpd
• Target in-service: 2017
• Marathon Funding:

37.5% of construction for ~27% equity interest in EEP ND system Flanagan



Sandpiper is expandable by 160 kbpd through horsepower upgrades



Low risk framework (ship-or-pay/COS)



Marathon is anchor shipper



Petition for Declaratory Order approved by FERC May 2014



Sandpiper provides access to premium PADD II market

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Line 3 Replacement

• 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)

ENB Funded EEP/ENB Joint Funded

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Risk Profile – Low Risk Business Model

Defensive nature of cash flows position EEP to navigate through commodity price uncertainty

Unconsolidated View

32% 27% 18%

Crude oil projects progressively transform EEP to much 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.

2017e 2015e

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Initial Drop Down:

• $1 billion drop down from Enbridge

closed 1/2/2015

• 66.7% interest in the U.S. segment of

Alberta Clipper pipeline (Line 67)

• Immediately accretive
• 2.7% distribution increase announced
• No public equity required by EEP

Drop Down Outlook:

• Enbridge reviewing potential larger

scale drop-down plan to EEP (1)

• Over $10 billion of U.S. liquids

pipeline assets available

• Eastern Access & Mainline Expansion

15% upsize options at cost

Drop Downs Boost Distributable Cash Flow

Enbridge reviewing potential larger scale drop-down plan to EEP (1)

Line 67

(1) On December 3, 2014, Enbridge Inc. ("Enbridge" or "ENB") announced it is reviewing a potential restructuring plan that would involve the transfer of its directly held U.S. liquids pipeline assets to Enbridge Energy Partners, L.P., a U.S. affiliate of Enbridge. This review is underway and has not progressed to a conclusion.

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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

• Line 3 Replacement**

$0.4 (2018) ~ $0.9

• Southern Access

Extension

• ~ $0.6
• Flanagan South
• ~ $2.8
• Seaway/Seaway Twin
• ~ $2.4

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

* Estimated capital cost or net book value of assets held by Enbridge Inc. ** Line 3 Replacement Joint Funding Agreement under consideration by a Special Committee of the independent Board of Directors., including an option to upsize EEP ownership by 15% one year after the in-service date.

~ $10B +

($ Billions)

Examples:

ENB Liquids Pipelines Drop-Down

Potential: $10 Billion +

        

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Key Takeaways

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

to an even lower risk business model

• Minimal equity funding requirements
• ENB reviewing potential larger scale drop-down plan to EEP (1)
• General Partner is strategically aligned with and invests in EEP
• Distribution growth: targeting 2% to 5% annual growth

Safety and operational reliability are cornerstones that underpin

• ur business and growth outlook

(1) On December 3, 2014, Enbridge Inc. ("Enbridge" or "ENB") announced it is reviewing a potential restructuring plan that would involve the transfer of its directly held U.S. liquids pipeline assets to Enbridge Energy Partners, L.P., a U.S. affiliate of Enbridge. This review is underway and has not progressed to a conclusion.

Supplemental Slides

Enbridge Energy Partners, L.P.

Investment Community Presentation January 2015

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Western Canada Supply Growth

0.0 1.0 2.0 3.0 4.0 5.0 6.0 7.0

Oil Sands Conventional Heavy Conventional Light & Medium Pentanes/Condensate

Forecast Western Canada Production

MMbpd

Source: CAPP – Crude Oil Forecast, Markets & Pipelines (June 2014)

Oil sands production projected to grow by an annual average of 170 kbpd through 2030

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North American Crude Oil Price Fundamentals

Light Differentials

1/22/15 1/30/13 Brent – WTI

• $19

LLS – WTI $1 $18 Asia – WTI $1 $22 WTI – Bakken $4 $3 WTI - Alberta Light $5 $6

Heavy Differentials

1/22/15 1/30/13 Maya – WCS $5 $39 Asia – WCS $4 $44

Significant Infrastructure Investment Opportunities

$48 $47 $39

Alberta Light

Bakken Brent Maya Asia $42 $48 LLS WCS $43 $34 $47

Light Crude Heavy Crude

$41 WTI

North American Supply North American Demand Transportation Bottlenecks Volatile Price Differentials

January 22, 2015 prices (in US$/bbl)

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Expected Project In-Service Period 1H13 2H13 1H14 2H14 1H15 2H15 1H16 2H16 1H17 2H17 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 Line 3 Replacement Natural Gas Projects (2) Ajax Plant Texas Express NGL Pipeline JV Beckville Plant

Low-Risk Sustainable Growth

(1) Eastern Access and Mainline Expansion liquids expansion projects jointly funded by EEP & ENB. Line 3 Replacement joint funding under consideration by independent Special

• Committee. 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

Distribution coverage strengthens as growth projects enter service

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Delivering Prudent Growth

(1) Eastern Access and Mainline Expansion Liquids projects 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) Assumed capex is proportionally funded based on EEP’s weighted average ownership of Midcoast Operating. (4) Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions. (5) 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 under

consideration by Independent Special Committee.

($MM) Growth Capital Net Capital EEP Target In-Service Risk Profile Liquids: Bakken Growth Projects Sandpiper 2,600 1,625 2017 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 6B Replacement, Line 5, Line 62 expansion 2,400 600 2Q 2013 – 2014 Line 6B Expansion + tankage 310 78 early 2016 US Mainline Expansion (1) Line 67 (Border to Superior) (4) Line 61 (Superior to Flanagan) 1,780 445 Phase 1 3Q14; Phase 2 2015-2016 Chicago Connectivity (Line 62 twin) 495 124 2H 2015 Line 3 Replacement (5) 2,600 1,300 2H 2017 30 year Cost of Service Natural Gas: Beckville Plant(3) 145 79 2015 Commodity & volume risk $10,330 $4,251

Midcoast Energy Partners, L.P.

Investment Community Presentation

January 2015

Forward Looking Statement

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This presentation includes forward-looking statements, which are statements that frequently use words such as "anticipate," "believe," "continue," "could," "estimate," "expect," "forecast," "intend," "may," "plan," "position," "projection," "should," "strategy," “opportunity”, "target," "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 ability of Midcoast Energy Partners, L.P. (the “Partnership”) to control or predict. The Partnership’s forward looking statements are 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 the following specific factors that could cause actual results to differ from those in the forward-looking statements: (1) changes in the demand for or the supply of, forecast data for, and price trends related to natural gas, natural gas liquids and crude oil; (2) the Partnership’s ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline and gathering systems, as well as

• ther processing and treating plants; (4) shut-downs or cutbacks at the Partnership’s facilities or refineries, petrochemical plants, utilities or
• ther businesses for which the Partnership transports products or to whom the Partnership sells products; (5) hazards and operating risks

that may not be covered fully by insurance; (6) changes in or challenges to the Partnership’s rates; and (7) changes in laws or regulations to which the Partnership is subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance; (8) cost overruns and delays on construction projects resulting from numerous factors. Forward-looking statements regarding “drop-down” opportunities are further qualified by the fact that Enbridge Energy Partners, L.P. is under no obligation to offer to sell us additional interests in Midcoast Operating, L.P., and we are under no obligation to buy any such additional interests. As a result, we do not know when or if any such additional interests will be purchased. Forward-looking statements regarding joint funding or investments in Partnership projects by Enbridge Energy Partners, L.P. (“EEP”) are further qualified by the fact that EEP has no obligation to participate in such projects, and there is no guarantee that it will do so. Except to the extent required by law, we assume no obligation to publically update or revise any forward looking statements, whether as a result of new information, future events or otherwise. In addition to the risks listed above, other risks include those detailed from time to time in the Partnership’s Securities and Exchange Commission, or SEC, reports, including, without limitation, in the Partnership’s Annual Report

• n Form 10-K for December 31, 2013 and any subsequently filed Quarterly Report on Form 10-Q or Current Report on Form 8-K, which

filings are available to the public at the SEC's website (www.sec.gov). In this presentation, unless the context otherwise requires, references to “Midcoast,” “the Partnership,” “MEP,” “we,” “our,” “us,” or like terms refer to Midcoast Energy Partners, L.P. We refer to Enbridge Energy Partners, L.P. as “Enbridge Energy Partners,” “Sponsor,” or “EEP.” References to “Midcoast Operating” or “MOLP” refer to Midcoast Operating, L.P.

VISION

Be recognized as a leading natural gas and NGL midstream infrastructure developer,

• perator and service provider in North America

CAPABILITIES REACH SCOPE SCALE

STRATEGY

Provide best in class gathering, processing and transportation solutions with a focus on safety, operational reliability and stakeholder engagement. We will increase our scale, scope, reach and capabilities across our business lines to deliver sustainable and industry leading growth to

• ur unit holders.

Increased size will provide for improved synergies and optimization

• pportunities while

creating a stronger financial foundation for investment grade credit ratings. We will be well-positioned to execute across our business lines through attracting, engaging and developing high-performing talent; by providing appropriate tools and resources; and by fostering knowledge sharing throughout the organization. We will expose our businesses to new market

• pportunities by diversifying

geographically and/or by commodity composition (e.g., wet, dry, treating, and gathering). An array of natural gas commodities and services in conjunction with core asset

• ptimization will significantly

augment our customer value proposition and improve our return on assets.

SCALE SCOPE REACH CAPABILITIES

Vision and Strategy

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MEP Strategic Priorities

• Strengthen underlying business

 Recontract and capture new business that enhances cash flow certainty  Continue focused cost management measures

• Secure and execute on organic growth opportunities

 Continue to enhance existing asset base by adding new supply and

• ptimizing assets
• Aggressively pursue accretive acquisitions

 Pursue geographic diversification and extend reach of existing asset base  Increase scale of enterprise  Enhance scope of business

• Position for future drop-downs from sponsor

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

Long-Term Transformation of Risk Profile

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2014 Risk Profile (1)

(1) Based on forecasted gross margin for 2014. Includes $19.6 million of distributions attributable to our 35% interest in the Texas Express NGL System. (2) Based on forecasted gross margin for Gathering Processing & Transportation segment for 2015. Includes $33.1 million of equity earnings and cash distributions in excess of earnings attributable to our 35% interest in the Texas Express NGL System.

Other Fee- Based 42% Commodity Sensitive 10% Hedged 40%

8% Est. Demand or Volume Commitment

Future State Risk Profile Demand-based revenue growth is a key strategic priority Risk profile transforms as base business grows and new business is captured

• Demand volumes and revenue progressively ramping on Texas Express
• Re-contract and capture new business that enhances cash flow certainty

Other Fee- Based Hedged Commodity Sensitive Demand or Volume Commitment

2015e Risk Profile (2)

Demand- Based ~11% Other Fee- Based ~42% Commodity Sensitive ~6% Hedged ~41%

 Drop-down program is strategic to EEP

• Position for 2H 2015 drop-down

 Secure growth opportunities  Cost management measures bolster distributable cash flow

IPO July 1, 2014 2017e Natural Gas business

• wnership

61% 39%

100%

51.6% 48.4%

Growth Outlook

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Strong Sponsor Support

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EEP incentivized to invest alongside MEP

• Jointly fund on and off footprint growth

EEP evaluating other forms of support Execute drop-down that enhances accretion at MEP

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

Sponsor aligned and incentivized to ensure MEP success

Enhance MEP Cost of Equity

Strategically Positioned Asset Base

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Anadarko System Texas Express NGL System North Texas System East Texas System Beckville Processing Plant - 2015

Petal

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

Midcoast Business Segments

 Gathering, Processing & Transportation: strong asset foundation ~ 90% EBITDA  Logistics & Marketing ~ 10% EBITDA

CLINE SHALE EAGLEBINE COTTON VALLEY

Regional Outlook

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* Eaglebine rig count as of January 16, 2015

Gathering, Processing & Transportation Highlights

East Texas

• Beckville plant 2015 in-service
• NGL production volumes expected to increase
• Eaglebine activity encouraging – 36 active rigs *

North Texas

• New gathering lines in Marble Falls play in-service
• Evaluating additional expansion opportunities in 2015

Anadarko

• Expect recent upstream M&A activity in the basin to spur

additional development.

• Fee-based arrangements transitioned to demand-based

Texas Express NGL System

• Ramp-up of committed volumes on NGL Mainline
• Execute and build upon natural gas, NGL and condensate
• ptimization strategies
• ~60% of segment gross margin typically earned in 1Q & 4Q

Logistics & Marketing Highlights

Texas Express – A Growing Base of Secure Cash Flow

Mainline System Volume Commitments

• 50,000

100,000 150,000 200,000 250,000 2014E 2015E 2016E 2017E 2018E 2019E 2020E 2021E 2022E Bpd Midcoast All Other Shippers

Texas Express NGL System

• Shipper committed and spot volumes ramping up; committed volumes step-

up to 147,000 Bpd in July 2015

• Underpinned by fee-based demand revenue
• System is expandable to ~400,000 Bpd
• Expected year-over-year cash flow increase of ~$12 million

Growth in demand revenue provides secure foundation

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Volume commitments represent annual averages.

Capital Forecast & Funding Outlook

Capital Expenditures(1)

2014e 2015e Beckville Gas Processing Plant $105 $15 Well Connect Expansion Capital 55 55 Compression Capital 20 50 Expansion Capital 105 205 Maintenance Capital 60 65 Total Midcoast Operating Capital $345 $390 Less: Joint funding from EEP(2) $185 $190 Total MEP Capital Forecast $160 $200

(1) Represents capital expenditure forecast at Midcoast Operating level. Capex to be proportionally shared between EEP and MEP based on ownership interest in Midcoast Operating, L.P. (MOLP). (2) 2014 joint funding based upon 6 months of EEP's 61% ownership of Midcoast Operating and 6 months of EEP ownership at 48.4% of Midcoast Operating. 2015 joint funding forecast is based upon 12 months of current EEP ownership at 48.4% of Midcoast Operating. (3) On October 30, 2014, the General Partner of MEP approved the termination of the Working Capital Credit Facility with EEP, the lender.

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Beckville Plant Construction

Growing Financial Strength:

• Coverage expected to strengthen
• Debt/EBITDA expected to improve

 Debt/EBITDA 2015 Target < 3.5x

• Managing lower working capital
• Sufficient liquidity to fund base capital

program

 $850MM credit facility  Secured $400 million term debt

Available Liquidity

485 375

250 250 66 236

• 200

400 600 800 1,000 9/30/2014 6/30/2014 $ millions

Available Credit Working Capital Facility Cash

$801 MM $861 MM

(3)

• Accelerating Scope & Pace of Change

Bottom-line enhancement initiatives

• ~ $50 million of annual cost reductions at

Midcoast Operating

• Cost structure to be commensurate with

current level of operations

• Workforce and contractor reduction (3)
• Idle and consolidate underutilized assets
• Eliminate discretionary expenditures
• Full-year benefit from 2014 cost reduction

actions

Management incentive compensation aligned with unitholder

• Distributable cash flow per unit growth
• Unit price appreciation relative to G&P peer

group

Cost containment measures to boost distributable cash flow

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2014e O&A Costs (1) $405 MM

New Assets In Service +~$12 Insurance & Taxes +~$6 Inflation +~$7

2015 O&A Baseline ~$430 MM O&A Cost Reductions (~$50) 2015e O&A (2) ~380 MM ~15% reduction in controllable expenses

(1) Represents forecasted Operating & Administrative costs at Midcoast Operating, L.P. for 12 months ended December 31, 2014, net of $25 million G&A abatement. (2) Represents forecasted Operating & Administrative costs at Midcoast Operating, L.P. for 2015e, net of $25 million G&A abatement. (3) Midcoast Operating expects to incur a one-time charge for severance costs in 4Q14 of approximately $6 million. These severance costs are not included in the 2014 full year $430 million operating & administrative cost estimate.

2015 Financial Outlook

(1) “Midcoast Operating Adjusted EBITDA, inclusive of other cash items” includes equity earnings and cash distributions in excess equity earnings from joint venture investment in Texas Express NGL system, in addition to $25 million G&A abatement. (2) Forecast assumes drop-down of additional interests of Midcoast Operating in 2015 by Enbridge Energy Partners.

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Midcoast Operating, L.P.

($ millions)

2015e

Adjusted EBITDA, inclusive of other cash items(1) $255 - $280 + 25% YoY

Midcoast Energy Partners, L.P. (MEP)

($ millions)

2015e

Adjusted EBITDA (2) $120 - $135 + 67% YoY Distributable Cash Flow $80 - $95 + 71% YoY Coverage 1.05X–1.20X Leverage < 3.5 X

Operating Assumptions 2015e

Natural Gas Volumes (MMbtu/d) Vs 3Q14 YTD Anadarko 825 – 900 +6% East Texas 1,050 – 1,150 +8% North Texas 300 – 330 +8% 2,175 – 2,380 +7% NGL Production (Bpd) 88,000–92,000 +9%

Positioned to deliver on 2015 financial guidance

• Accelerating pace and increasing scope of change

 Executed cost reduction measures bolster distributable cash flow  Adding to demand-based business

• Sponsor support remains strong

 Drop-down strategy intact

• Aggressively pursuing accretive growth

 Key development focus on entry into prolific new basins

• Growing financial strength:

 Strengthening coverage  Improving leverage  Positioned to deliver 2015 financial guidance

Key Takeaways

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Appendix

Strengthening Business Performance

$ 220 $ 255 $ 280

150.0 170.0 190.0 210.0 230.0 250.0 270.0 290.0

MOLP Adjusted EBITDA, inclusive of other cash items (1)

($ millions)

37 midcoastpartners.com

(1) MOLP Adjusted EBITDA, inclusive of other cash items includes equity earnings and cash distributions in excess equity earnings from joint venture investment in Texas Express NGL system, in addition to $25 million G&A abatement. (2) O&A Cost Reductions shown net of forecasted higher insurance, property tax, and inflation in 2015. (3) Drop-down from EEP cash flow impact at MEP.

1Q15e 2Q15e 3Q15e 4Q15e  Logistics & Marketing Seasonal Uplift  Beckville ramp-up  Texas Express ramp- up  Logistics & Marketing Seasonal Uplift  Beckville plant in service  Drop-down from EEP (3)

2015 Earnings and Cash Flow Outlook

2015 Commodity Gross Margin Largely Secured

38 midcoastpartners.com 2015 Commodity Price Sensitivity Analysis (2)

(1) Represents Estimated Commodity Positions for the Gathering, Processing and Transportation Segment of Midcoast Operating, L.P. as of 11/28/2014. Unaudited, $ in millions. Options valued at their strike prices to determine hedged cash flows. (2) Commodity sensitivity of unhedged commodity positions for the Gathering Processing & Transportation segment at Midcoast Operating as of 12/1/2014. (3) Portfolio hedge percentage based on commodity positions and forward prices as of 12/1/2014.

2015 Estimated Commodity Positions & Hedged Cash Flows (1)

(15) (10) (5)

• 5

10 15 2015

Prices: -10% Prices: +10%

$ millions

~80% of 2015 commodity cash flows hedged (3)

Hedge Weighted Avg Hedged Cash Flows % Hedge Price $ MM Natural Gas (9,711) MMbtu/d 0% MMbtu/d $0.00 /MMbtu ($0.2) C2 6,918 bpd bpd $0.00 /gallon $0.0 C3 6,526 bpd 80% 5,250 bpd $0.93 /gallon $75.1 iC4 1,388 bpd 54% 750 bpd $1.06 /gallon $12.2 C4 2,276 bpd 59% 1,349 bpd $1.04 /gallon $21.5 C5 1,100 bpd 95% 1,050 bpd $1.90 /gallon $30.6 Total NGLs 18,208 bpd 46% 8,399 bpd $139.4 Condensate 4,019 bpd 72% 2,910 bpd $85.12/barrel $90.4 Hedged Commodity Gross Margin $229.6 Equity Length Volume

Estimated Commodity Positions

Physical Hedged

39 enbridgepartners.com

Corporate Structure

Corporate structure as of January 2, 2015

48.4% LP interest 46% LP interest 2% GP interest 52% LP interest 49.1% LP interest

Public Unitholders

88.3% of listed shares

Public Unitholders

2% GP interest 32.8% LP interest (indirect)

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

16.1% LP interest (I-units) 11.7% of listed shares 100% voting interest

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

51.6% LP interest

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

Enbridge Inc. owns ~37% of EEP