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Legal Notice
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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
or factor on any particular forward looking statement is not determinable with certainty as these are independent and our future course
of 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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Strong Business Fundamentals: Strength & Stability
Migrating to a Much Lower Risk
Business Model
Strong General Partner
Stable Distributions & Prudent Growth
Attractive Yield
Investment Proposition
3
Investment Highlights
4
*Enterprise Value as of 12/4/14; **Return CAGR since inception to 12/4/2014 (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
Total Shareholder Return
1991 2014
Enterprise Value -
Large-Cap MLP
Commercially
secured organic
growth underway
Strong Investment Grade (S&P, Moody’s, DBRS) Low-risk transformative
growth underway
~$2.3 billion of growth capital placed in service
Equity restructure to reset IDRs and establish single tier IDR structure
~$900 million initial drop-down proposal from ENB received
ENB is reviewing restructuring plan to drop-down its U.S. liquids pipeline assets to EEP
Highlights
2014 Highlights
$0
$20,000
$40,000
$60,000
$80,000
$100,000
$120,000
$140,000
65% 62%
19%
• Owner and operator of largest crude
oil pipeline system
• ~$45 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.
5
ENB: North American leader in
energy delivery
Strategic Position
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Norman Wells
Zama
Portland
Seattle
Casper
Montreal
Salt Lake City
Patoka
Cushing
Ottawa Superior
Chicago
Clearbrook
Regina
Flanagan
Hardisty
Toledo
Toronto
Sarnia Buffalo
Wood
River
Edmonton
Fort McMurray
Houston
St. James
Philadelphia
Cromer St. John
WCSB
BAKKEN
EEP Contract Storage
EEP Liquids Pipelines
ENB Liquids Pipelines
Competitive Advantages
• Refiners
– Access to multiple crude streams
• Producers
– Access to multiple premium markets
• Flexible system
• Size and scale unmatched
– Will expand to ~2.85 MMb/d in 2017
Positioned for Long-Term Growth
• Direct connection to growing supply basins (Heavy
& Light)
High quality customer base
ENB and EEP Strategically Aligned
OTHER
ENB
0.0
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
MMb/d
2014 Enbridge Forecast Optimal Pipeline Capacity
Supply Forecast
WCSB Supply Forecast vs. Pipeline
Takeaway Capacity*
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*Includes Bakken entering ENB Mainline ex-Superior Sources: Enbridge Internal Forecast
Keystone XL
ENB Northern Gateway
TransMountain Expansion
Energy East
Bakken Crude Supply and Pipeline
Takeaway Capacity
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Range of External Forecasts
0
500
1,000
1,500
2,000
2,500Kbpd
High Case Low Case
3rd Party Pipes
Local Refining
Enbridge - Bakken
3rd-Party Proposed
Enbridge - Sandpiper
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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
of 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
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
• ~$0.2 billion capital
* Jointly funded 25% EEP / 75% ENB
Commercially Secured
30 year Cost of Service
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
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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
Line 3 Replacement
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ENB Funded
EEP/ENB Joint Funded
Increases system reliability and flexibility
• 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)
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Commercial Structure & Risk Profile
Crude oil projects progressively transform EEP to lower risk business model
Cost of Service/Take-or-Pay: Contribution from Liquids and Natural Gas business cost of service and take-or-pay contracts.
Fee-based: Contribution from Liquids and Natural Gas business fee-based service. Commodity Sensitive: Contribution from Natural Gas business from its commodities length (before hedging).
Contribution is based on revenues from Liquids segment and gross margin from Natural Gas segment, after deducting non-controlling interest.
Assumes Natural Gas business dropped down to MEP within five years.
0.0%
20.0%
40.0%
60.0%
80.0%
100.0%
2011 2012 2013 2014 2015 2016 2017
59%
23%
18%
Cost-of-Service/Take-or-Pay
Commodity Sensitive
Fee-Based 24%
76%
(Unconsolidated view)
Operational Risk Management Program
Industry Leadership
Third Party Damage
Avoidance and
Detection
Incident Response
Capacity
Employee and
Contractor
Occupational Safety
Public Safety and
Environmental
Protection
Integrity Management
Leak Detection
Capability and
Control Systems
• State-of-the art Liquids Pipelines control center
• Most extensive maintenance, integrity and inspection program in the history of the North
American pipeline industry
• Liquids Pipelines completed 615 in-line inspections and 8,975 verification digs (2010-2013)
Priority One – Focus on Safety &
Operational Reliability
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Initial Drop Down:
• $900 million drop down proposal from
Enbridge
66.7% interest in the U.S. segment of
Alberta Clipper pipeline (Line 67)
• Immediately accretive to DCF/unit ~ 3%
No public equity required by EEP
Drop Down Outlook:
• Initial drop down paves the way for
future drop downs from Enbridge
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
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Enbridge reviewing larger scale drop-down plan to EEP
Line 67
ENB Liquids Pipelines
Drop-Down Potential: $10 Billion +
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2017e
Distributable
Cash
ENB Drop-Down Backlog:
Upsize Option- Eastern Access and Mainline Expansions
Alberta Clipper
Eastern Access
Mainline Expansions
Line 3 Replacement
Spearhead
Flanagan South
Seaway/Seaway Twin
Other
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.
** Drop-down proposal for remaining 66.7% interest in Alberta Clipper received from Enbridge for approximately $900 million.
*** 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:
Key Takeaways
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• Strategic position supported by strong business fundamentals
• Secured Liquids projects collectively transform the Partnership
to an even lower risk business model
• Minimal equity funding requirements
• Enbridge reviewing larger scale drop-down plan to EEP
• 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
our business and growth outlook
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