Enbridge Energy Partners, L.P.

September 2016 Investment Community Presentation

Legal Notice

SLIDE 2

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,” “consider,” “continue,” “could,” “estimate,” “expect,” “explore,” “evaluate,” “forecast,” “intend,” “may,” “opportunity,” “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 or drop-down opportunities; (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) costs in connection with complying with the settlement consent decree related to Line 6B and Line 6A, which is still subject to court approval, and/or the failure to receive court approval of, or material modifications to, such decree; (7) changes in or challenges to the Partnership’s tariff rates; (8) 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; and (9) permitting at federal, state and local levels in regards to the construction of new assets.

“Enbridge” refers collectively to Enbridge Inc. and its subsidiaries other than the Partnership and its subsidiaries.

Forward-looking statements regarding “drop-down” growth opportunities from Enbridge are further qualified by the fact that Enbridge 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, L.P. are further qualified by the fact that we are under no obligation to sell to Midcoast Energy Partners, L.P. any such interests, and Midcoast Energy Partners, L.P. is under no obligation to buy any such interests. As a result, we do not know when or if any such transactions will occur.

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 year ended December 31, 2015 and any subsequently filed Quarterly Report 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.

$0

$50,000

$100,000

$150,000

$200,000

$250,000

EEP Total Shareholder return S&P 500 Utilities

Investment Highlights

SLIDE 3

~$20B* Enterprise Value Large-Cap MLP

BBB, Baa3, BBB Strong Investment Grade (S&P, Moody’s, DBRS)

*Market capitalization and yield as of 9/21/16; **Return CAGR since inception to 9/21/2016 (nominal)

Pure-Play Liquids Pipeline MLP

Low-risk Growth Underway

Utility-like MLP Defensive cash flow

risk profile

Sept 2016 1991

Ticker Symbol NYSE: EEP

Market Capitalization* $11.8 Billion

Yield* 9.5%

Current Cash Distribution $2.332/unit annual Total Unitholder Return (CAGR since inception)** 11.4%

Incorporated 1991

Total Assets $18.8 Billion

Assets

• ~6,100 miles liquids pipelines • ~20MM barrels merchant crude

storage • 17 active natural gas processing

plants

Total Unitholder Return

Well Positioned for Current Environment

<5% of business cash flows subject to direct commodity exposure

Low-risk, reliable business model provides highly certain cash flows

>90% of Partnership cash flows from Liquids segment

>90% of revenues from investment grade customers

Long-term, low-risk commercial structures in

core liquids pipelines business

1 Commodity sensitive gross margin forecast is before hedging; greater than 90% of 2016e commodity sensitive cash flows are hedged substantially above current market prices. 2 EEP consolidated (including MEP) and net of Accounts Receivable purchased by affiliate of Enbridge.

SLIDE 4

Cost of Service/Take-or-Pay

Fee for Service Commodity sensitive1 Investment Grade Non-Investment Grade

Commercial Structures Counterparty Credit Profile2

0

1

2

3

4

5

6

2016 2018 2020 2022 2024 2026 2028 2030

Western Canadian Refineries

Other Existing Pipelines

Enbridge

Strong Western Canadian Supply Outlook and Demand for Pipeline Capacity

Strong demand for pipeline capacity = high system utilization

~660 kbpd oil sands supply growth through 2020

Basin short ~700 kbpd pipeline capacity by 2020 when considering crude slates

0

0.5

1

1.5

2

2.5

3

Q32014

Q42014

Q12015

Q22015

Q32015

Q42015

Q12016

Q22016

Oil Sands Growth Incremental WCSB Blended Heavy Supply Growth*

(cumulative kbpd)

Pipeline Capacity vs. WCSB Supply* (MMbpd)

SLIDE 5 *Source: CAPP Crude Oil Forecast, Markets and Transportation (June 2016 )

0100200300400500600700

2017 2018 2019 2020

Lakehead Deliveries (MMbpd)

Impact from Alberta wildfires

Western Canadian Supply Profile vs. Crude Price

SLIDE 6

History demonstrates steady oil sands production growth in all price environments

kbpd $US/bbl

0

20

40

60

80

100

120

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000WCSB Production Enbridge Ex-Gretna Deliveries WTI Annual Avg ($US/bbl)

Sources: CAPP, Bloomberg

Our Strategy: Stability + Growth

SLIDE 7

The foundation for delivering sustainable growth

Strategic Position • Exceptional liquids pipeline infrastructure network

• Connectivity to large producing basins and key North American refining centers

Low-risk business model delivers stable cash flows • >90% of cash flows are backed by long-term cost-of-service, take-or-pay or fee-based • Organic growth and drop-down potential further transition business to even lower risk

Robust Organic Growth • Liquids pipeline organic growth program underway

• Well positioned to secure additional low-cost, phased expansions

Premier MLP Sponsor: Enbridge Inc. • Industry-leading $25 billion secured organic growth program underway at ENB • >$10 billion of U.S. Liquids Pipelines assets available for potential drop down

Competitive Advantages

• Refiners: Access to multiple crude streams

• Producers: Access to multiple premium markets

• Flexible system; low-cost provider

• Size and scale unmatched: 2.85 MMbpd Mainline capacity

Positioned for Long-Term Growth

• Direct connection to growing supply basins (Heavy & Light)

High quality customer base

ENB and EEP strategically aligned

Foundation for Delivering Sustainable Growth

SLIDE 8

Strategic position: largest pipeline transporter of growing oil production from Western Canada and Bakken

Houston

Port Arthur

Cushing

Portland

Seattle

Wood River

Patoka

Flanagan Chicago Toledo

Sarnia

Toronto Buffalo

Montreal

Superior Clearbrook

Gretna Cromer

Regina

Hardisty Edmonton

Cheecham

Fort McMurray

Zama

Norman Wells

Regional Oil Sands

Mainline System

North Dakota System

Lakehead System

Seaway

Line 9

ENB Liquids Pipelines

EEP Liquids Pipelines

EEP Contract Storage

Mid-Continent System

Foundation for Delivering Sustainable Growth

SLIDE 9

Demand pull: pipeline system accesses 8.5 MMbpd of refining capacity

Premier connectivity to North American refining centers

Expanded market access

Competitive transportation

rates

Strong Demand for Pipeline Systems Key Markets Served by the Enbridge System

*Excludes NGLs Source: Enbridge estimates and EIA data

2016e EBITDA (1)

Low-Risk Business Model Delivers Stable Cash Flows

SLIDE 10

Liquids pipeline business generates greater than 90% of Partnership’s distributable cash flow

• Hedging program largely mitigates commodity price risk

• Utility style regulatory model: ‘return-of’ and ‘return-on’ invested capital

• Highly predictable cash flows

- No volume and commodity price sensitivity

• Rate base comprised of equity and debt components

Liquids Segment ~85% of fee-based component • Pipeline toll indexed to PPI + 1.23%(3)

• System highly utilized Natural Gas Segment ~15% of fee-based component

Fee-Based

Cost of Service (Liquids Segment)

Commodity Sensitive(2) (Natural Gas Segment)

(1) Contribution is based on revenues from Liquids segment and gross margin from Natural Gas segment, after deducting non-controlling interest. (2) Commodity sensitive gross margin forecast is before hedging; greater than 90% of 2016e commodity sensitive cash flows are hedged substantially above current market prices. (3) FERC index annual adjustment of PPI + 1.23%. (prior index adjustment of PPI + 2.65% expired June 30, 2016).

Liquids Pipelines Remaining Contract Life

SLIDE 11

Long-term, low-risk commercial structures underpin liquids pipeline revenues

0 10 20 30

Mainline Expansions

Eastern Access

Alberta Clipper

Southern Access

Lakehead System: years years

North Dakota System: toll indexed to PPI + 1.23%(1)

Mid-Continent System: toll indexed to PPI + 1.23%(1)

years

(1) FERC index annual adjustment of PPI + 1.23%. (prior index adjustment of PPI + 2.65% expiried June 30, 2016). (2) 30 year cost of service agreement, with 15 year initial term.

Lakehead base toll indexed to PPI + 1.23%(1)

Cos

t-of-S

ervi

ce

Fee-

base

d

(2)

Foundation for Delivering Sustainable Growth

SLIDE 12

Premier MLP Sponsor: Enbridge Inc. (ENB)

Note: Standard & Poor’s/Moody’s/DBRS credit ratings respectively. Market capitalization in USD as of 9/21/2016

ENB: A leader in energy delivery • Owner and operator of largest crude oil pipeline

system

• ~$41 billion equity market cap

• Strong investment grade (BBB+, Baa2, BBB+)

• Proven track record: industry leading EPS and DPS growth

• 13% 10-year TSR CAGR

• 14% 10-year DPS CAGR

• 10% - 12% DPS growth forecast 2016-2019

• Strategy aligned with Partnership

• ~$25 billion enterprise-wide secured organic growth program underway

Wind

Solar

Gas Distribution

Storage

Liquids Pipelines

Gas Pipelines

Three Pillars of Growth

SLIDE 13

Drop-downs from Sponsor

EEP

Diversified Growth Platform

• Single-tier IDR structure

• Commercially secured organic growth underway

• Low-cost, phased expansion opportunities

• Strategic alignment with sponsor

Pillar #1: Market Access Well Advanced

SLIDE 14

Transformative low-risk organic growth expected to provide substantial cash flow growth

Organic Growth Projects: • Commercially secured • Low risk framework • Long-term contracts

Incremental Market Access by 2019: +1.0MMbpd of Heavy +0.7MMbpd of Light

Light

Heavy

+600 kbpd

+300 kbpd

+250 kbpd

+50 kbpd +250 kbpd

+50 kbpd

+50 kbpd +80 kbpd

Eastern Access Western USGC Access

Light Oil Market Access

Pillar #2: Expansion & Extension Opportunities

Western Canadian expansion project suite

Market extension low-cost expansions

Pipeline Description Capacity (kbpd)

Execution Comments

Line 3 Restore capacity

400 No cross border permitting required

Line 4 Rate optimization

50 No cross border permitting required

Line 2 Eliminate ND receipts

150 Requires restoration of Line 2 capacity

Line 65 Additional pumping

100 NEB & State approvals required

Line 3 Additional pumping

100 NEB & State approvals required

Total 800 Upstream Capacity

Well positioned to pursue additional expansions to meet shipper needs; phased expansions are attractive in a low crude price environment

SLIDE 15

Scalable, incremental, low-risk, and highly executable

Pillar #3: Enbridge U.S. Liquids Pipelines Drop Down

SLIDE 16

Attractive, low-risk U.S. liquids pipeline assets available for potential drop down

Pipeline System Risk Profile

Eastern Access

Mainline Expansion

Line 3 Replacement

Southern Access Extension

Flanagan South

Seaway/Seaway Twin

Spearhead

Toledo

B A

B

A

C

D

E

F

D

E

F G

H

G

H

Cost-of-Service/Take-or-Pay

Indexed Toll (fee-based)

C

Crude Oil Fundamentals and the Enbridge System

WCSB Crude Supply Forecast

SLIDE 18

Western Canadian producers have a long-term investment horizon

Source: CAPP – Crude Oil Forecast, Markets and Pipelines (June 2016)

• Incremental economics of projects in construction

• Long-term price views

• Synergies with existing operations

• Cost reductions

• Integrated operations

0

1,000

2,000

3,000

4,000

5,000

6,000

2016 2018 2020 2022 2024 2026 2028 2030

Kbp

d

Total Conventional Upgraded Light (Synthetic) Oil Sands Heavy

Pipeline Capacity vs. Supply Outlook

SLIDE 19

Strong demand for pipeline takeaway capacity out of Western Canada

Regina Deliveries

Western Canadian Refineries 0

1

2

3

4

5

6

2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

CAPP June 2016 Supply Forecast

Near term optimization: +60 – 80 kbpd

Enbridge

Western Canadian Refineries

Other Existing Pipelines

Bakken Crude Supply Forecast

SLIDE 20

Highly productive and economic resource base; pipeline access to market enhances producer netbacks

• ~75% of resource base in 4 core counties (McKenzie, Dunn, Mountrail and Williams)

• Highest productivity wells

• Most potential for future drilling

• Core counties remain relatively healthy, and operators remain selective within the region

• Enbridge system provides access to multiple premium markets

Bakken Crude Supply vs. Takeaway Capacity

Local refinery Enbridge pipelines

3rd Party Pipelines

Rail

0

500

1000

1500

2000

2500

3000

3500

2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027

kbpd

North Dakota Pipeline Authority (NDPA) Base Crude Oil Production Forecast (February 2016)

$/bbl Other Pipelines

Enbridge System

WCSB to Chicago Area ~$15 - $21 ~$5 - $6 ~$4

WCSB to Western USGC ~$15 - $22 ~$8 - $13 ~$7 -$11

Bakken to Chicago Area ~$10 - $12 - ~$3 - $4

Bakken to Montreal ~$12 - $14 - ~$5 - $7

Strong Competitive Position

SLIDE 21

Enbridge system is a reliable, low cost crude oil transportation provider with access to premium markets

WCSB

Western USGC

Montreal

Bakken

Chicago

Heavy

Light

Rail Transport

SLIDE 22

Matching Supply Push and Demand Pull

EEP Lakehead System matches supply and demand 2

CAPACITY(kbpd)

Mainline Connected Refineries 1,900Mainline Connected Markets (Pipeline Access) 1,575Total 3,475

Strong demand from refineries and connected markets❸

Production growth with limited alternative takeaway capacity ❶

Liquids Pipelines Growth Program

Acquired Interest in Bakken Pipeline System

SLIDE 24

System extends from the Bakken to USGC

ENB/EEP1 MPC ETP SXL

Enbridge/Marathon Joint Venture

Bakken Holdings Company

Bakken Pipeline Investments

PSX PSX

DAPL ETCO

75% 25% 60% 40%

49% 51%

75% 75%

25% 25%

Project Details

Assets: Bakken Pipeline System consists of Dakota Access Pipeline (DAPL) and Energy Transfer Crude Oil Pipeline (ETCO)

Capital: $1.5B

In-Service: Q4 2016

Capacity: ~470kbpd expandable to 570 kbpd

Effective Ownership:

27.6%

Expected Close: 2H 2016

1 An independent committee of the board of directors of the delegate of EEP’s general partner and Enbridge Energy Company, Inc. (EECI), a wholly owned subsidiary of Enbridge Inc. (ENB), have reached a tentative agreement on the terms of an arrangement through which each party would fund the acquisition of and participate in the returns generated by the investment in the Bakken Pipeline System.

Bakken Pipeline Investment

SLIDE 25

Accretive acquisition

1 An independent committee of the board of directors of the delegate of EEP’s general partner and Enbridge Energy Company, Inc. (EECI), a wholly owned subsidiary of Enbridge Inc. (ENB), have reached a tentative agreement on the terms of an arrangement through which each party would fund the acquisition of and participate in the returns generated by the investment in the Bakken Pipeline System.

Strategic Fit • Offers customers competitive tolls between the Bakken

and USGC • Joint toll opportunity with Enbridge mainline • Highly contracted: secured by long-term take-or-pay

commitments • High credit quality counterparties: >90% investment grade • Expansion opportunities Funding Plan

• Anticipate that the investment will be funded 25% by EEP and 75% by ENB1

• EEP would issue a new class of limited partner units to ENB to substantially fund its 25% investment (PIK feature)

• Joint funding arrangement would provide for a call option for EEP to upsize its interest by 15%, at book value

Line 3 Replacement

SLIDE 26

Enbridge system operating capacity from Western Canada increases to 2.85 MMbpd; project provides high reliability and assurance to key markets

EEP Capital Investment

• Border to Superior ~$2.6 billion capital

• To be joint funded with ENB

Expected Completion:

• Early 2019

30 year Cost-of-Service

• 15 year primary term

Shipper Support (CAPP/RSG)

Financial Outlook and Risk Management

Funding Outlook

Manageable funding needs • Significantly reduced 2016 capital expenditures, ~$885MM • Based on liquidity position and combined with current equity valuation, do not expect to

access equity market in 2016 • Addition of $750MM 364-day credit facility with Enbridge (U.S.) Inc. in July1

Joint Funding with sponsor enhances financial flexibility • Bakken Pipeline System acquisition and Line 3 Replacement project joint funding

proposals being reviewed2

Credit metrics and distribution coverage strengthen as projects enter service • Cost of service and take-or-pay structures to deliver highly certain cash flow growth

Maintaining investment grade rating remains a priority

SLIDE 28 1 On July 26, 2016, EEP entered into an unsecured revolving 364-day credit agreement with Enbridge (U.S.) Inc. 2 A joint funding proposal with Enbridge or one of its wholly owned subsidiaries for the Line 3 Replacement is under consideration by an Independent Committee of the Board of Directors and participation levels have not yet been determined. A tentative agreement has been reached between an Independent Committee of the Board of Directors and EECI on the terms of an arrangement through which each party would fund the acquisition of and participate in the returns generated by the investment in the Bakken Pipeline System.

Natural Gas Segment

SLIDE 29

Large-scale G&P assets along US Gulf Coast with access to multiple drilling formations

*Based on EEP 2016 forecasted adjusted EBITDA Note: EEP owns a 48.4% interest in Midcoast Operating, L.P.

Key Assets

Natural Gas Deliveries ~2.0 bcf/d

Gathering and Transportation Pipelines 10,900 miles

Active Natural Gas Processing Plants 17

Active Natural Gas Treating Plants 5

Texas Express NGL system 35% JV interest

EEP 2016e Segment EBITDA*

Natural Gas

Liquids

Strong Counterparty Credit Profile

SLIDE 30

Major liquids pipeline systems underpinned by strong, investment grade customers

EEP Customer Credit Quality (1)

(1) EEP consolidated (including MEP) and net of Accounts Receivable purchased by affiliate of Enbridge Inc.

MAINLINE TOP 10 SHIPPERS

Shipper 1: Integrated AA+/Aaa

Shipper 2: Integrated A-/A3

Shipper 3: Refiner BBB/Baa2

Shipper 4: Integrated A-/Baa1

Shipper 5: Refiner AA-/A1

Shipper 6: Integrated A/Aa2

Shipper 7: Refiner BBB/Baa2

Shipper 8: Refiner Credit enhancement to investment grade

Shipper 9: Midstream BBB/Baa3

Shipper 10: Refiner Credit enhancement to investment grade

Investment Grade Non-Investment Grade

Priority One – Focus on Safety & Operational Reliability

SLIDE 31

Operational Risk Management Program

• State-of-the art Liquids Pipelines control center

• Most extensive

maintenance, integrity and inspection program in the history of the North American pipeline industry

Key Takeaways

SLIDE 32

Business model attractive in all market conditions

Strategic position • Connectivity to large producing basins and key North American refining centers • Expanded market access underpins strong system utilization outlook

Well positioned for current environment • Defensive and low-risk business model; strong counterparty risk profile

Manageable funding needs • Maintaining investment grade credit rating remains a priority • EEP exploring strategic alternatives for its investments in Midcoast Operating and MEP

Diversified growth platform • Sustainable growth outlook: organic growth + ‘bolt-on’ expansion opportunities + drop-down

potential from sponsor

Premier MLP sponsor • Enbridge Inc. strategically aligned with the Partnership

Appendix Enbridge Energy Partners, L.P. Investment Community Presentation September 2016

Corporate Structure

SLIDE 34 Corporate structure as of September 21, 2016

48.4% LP interest

46% LP interest

2% GP interest (indirect) 52% LP interest

44% LP interest

Public Unitholders

88% of listed shares

Public Unitholders

2% GP interest (indirect) 38% LP interest (indirect)

Enbridge Inc. (NYSE: ENB) (Baa2 / BBB+)

Enbridge Energy Management, L.L.C.

(NYSE: EEQ)

16% LP interest (I-units)

12% of listed shares (indirect)

100% voting interest (indirect)

Enbridge Energy Partners, L.P. (NYSE: EEP) (Baa3 / BBB)

51.6% LP interest

Midcoast Operating, L.P. “Midcoast Operating”

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

Public Unitholders

Enbridge Inc. owns

~42% of EEP

0.001 GP interest (indirect)

Safety and Operational Reliability

• Primary components to terms of settlement with U.S. DOJ and U.S. EPA

• Civil penalties under Clean Water Act for 2010 incidents on Line 6B ($61 million) and Line 6A ($1 million)

• Safety measures cost estimated at $110 million over four-year term of the decree and is largely incorporated in operational and capital expense planning

• Pipeline replacement • Replaced Line 6B in 2014 • Replacement of Line 3, underway

• Focused first and foremost on the safety and operational reliability of our systems

• Fulfilled commitment to thoroughly clean up and restore area and to cover the costs

SLIDE 35

Line 6B Settlement

Line 6B and Line 6A Incidents

SLIDE 36

Amounts in millions of dollars.

Civil penalty under the Clean Water Act of U.S.

$61.0 Civil penalty under the Clean Water Act of U.S.

$93.7 Long-term monitoring

• Mix of capital and expense items • Items largely consistent with ongoing integrity

program

Line 6BTotal cost estimate accrued 1,223.0 Spent through 06/30/2016 1,068.3 Remaining liability 154.7

Line 6ATotal cost estimate accrued 52.0 Spent through 06/30/2016 51.0 Remaining liability 1.0

InsuranceCoverage 650.0 Proceeds collected through 06/30/2016 547.0 Remaining balance eligible for recovery 103.0

Injunctive Safety MeasuresEstimated cost over 4-year term of decree 110.0

Capital and Investment Expenditures

SLIDE 37

Adequate liquidity to fund base capital program

2016 CAPITAL AND INVESTMENT EXPENDITURES ($ millions)

Eastern Access1 50

US Mainline Expansions1 60

Sandpiper1 75

Line 3 Replacement 160

Liquids Integrity 265

Liquids Other Growth Enhancements 190

Natural Gas Growth Projects2 20

Maintenance Capital Expenditures2 65

Total Capital Expenditures 885 Eastern Access call option exercise 360

Line 3 Replacement joint funding scenario3 (~350)

Capital and Investment Expenditures +/- 885

414 646

125

87

750

0

200

400

600

800

1,000

1,200

1,400

6/30/2016 3/31/2016

Credit Facilities Cash Pro-forma

$539

$1,289

$733

Available Liquidity ($ millions)

1 Eastern Access and US Mainline Expansion capital expenditures are forecasted net of joint funding, with assumed Enbridge 75% funding. Sandpiper capital expenditures are forecasted net of 37.5% joint funding from Marathon Petroleum Corp. The joint funding by Enbridge is based on the respective economic interest in the Eastern Access and Mainline Expansions project series and do not take into account the temporary adjustment to distributions and contributions pursuant to Amendment of OLP limited partnership agreement.

2 Represents EEP’s share of Natural Gas capital expenditures of Midcoast Operating, L.P., (“MOLP”) which will be proportionately funded between EEP and Midcoast Energy Partners, L.P. (“MEP”). Forecast reflects current base 48.4% funding by EEP and 51.6% by MEP. 3 The Line 3 Replacement project participation level with Enbridge is under consideration by an Independent Committee of the Board of Directors and no decision has yet been reached. This amount reflects one possible scenario and represents the approximate dollars that

would be remitted to EEP by Enbridge as the capital contribution of Enbridge for an economic interest in the jointly funded project. 4 On July 26, 2016, EEP entered into an unsecured revolving 364-day credit agreement with Enbridge (U.S.) Inc.

Proforma: $750 million 364-day Credit Facility

with Enbridge (U.S.) Inc.4

Preferred Unit Restructuring

SLIDE 38

Enhances Partnership’s financing flexibility

Term Prior Restructured

Principle Rate $1.2 Billion/ 7.5% Unchanged

Distribution Becomes Cash Paying Q3 2015 Q3 2018

Accumulated Deferred Distribution Becomes Payable

Earlier of unit redemption date or May 2018

Q1 2019 (Payment beginning May 2019) Amortize equally over 12 quarters

Rate Reset Date May 8, 2018 UST 5 Yr +620 bp

June 30, 2020 (same terms)

Conversion Option Date to Class A After June 1, 2016 After June 1, 2018

Bakken Infrastructure

SLIDE 39

Largest pipeline transporter of crude oil from the Bakken region to premium markets

Regulatory Tolling Framework

SLIDE 40 (1) Can revert to Cost of Service tolling governed by the FERC by demonstrating substantial divergence between costs and rates. (2) NEB base is the annually published NEB Multi-Pipeline rate of Return FERC Index = + 1.23%. (prior index adjustment of PPI + 2.65% expiried June 30, 2016).

System Regulatory Methodology

Lakehead System Base Toll Toll Indexed to PPI + 1.23%

Southern Access Cost of Service at 9% ROE; 55% equity, 45% debt rate base + Tax Allowance

Alberta Clipper Cost of Service at NEB basic(2) + 2.25% ROE; 55% equity; 45% debt rate base + Tax Allowance

Facilities Surcharge Mechanism (FSM)

Cost of Service at 11.5% ROE; 55% equity, 45% debt rate base + Tax Allowance • Includes Eastern Access and Mainline Expansion projects

North Dakota Toll Indexed to PPI + 1.23% (Fall back is cost of service(1))

Phase V-VI Expansion Cost of Service

Mid-Continent Toll Indexed to PPI + 1.23% (Fall back is cost of service(1))

Contract – based for storage

Major Canadian and US Crude Oil Pipeline and Refineries

SLIDE 41

Alternative Ways to Invest in our MLP

SLIDE 42

Tax Considerations

* Form 1099 issued for tax year during which shares are disposed.

Ticker Symbol: EEQ (NYSE) EEP (NYSE)

Allocated Taxable Income No Yes

Mutual Fund Limitations No Yes

Unrelated Business Income Tax No Yes

Schedule K-1 No Yes

Form 1099 Yes* No

State Filing Obligations No Yes