Legal Notice
2
This presentation includes certain forward looking information (“FLI”) to provide Enbridge Energy Partners, L.P. (“EEP”) and Enbridge
Energy Management, L.L.C. (“EEQ”) investors and potential investors with information about EEP and EEQ and management’s
assessment of the future plans and operations, which may not be appropriate for other purposes. FLI involves statements that frequently
use words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,”
“projection,” “should,” “strategy,” “will” and similar words. Although we believe that such forward looking statements are reasonable based
on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance.
Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking
statements. Many of the factors that will determine these results are beyond EEP’s ability to control or predict. Specific factors that could
cause actual results to differ from those in the forward-looking statements include: (1) changes in the demand for or the supply of,
forecast data for and price trends related to crude oil, liquid petroleum, natural gas and NGLs, including the rate of development of the
Alberta Oil Sands; (2) EEP’s ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular,
by other pipeline systems; (4) shut-downs or cutbacks at facilities of EEP or refineries, petrochemical plants, utilities or other businesses
for which EEP transports products or to whom EEP sells products; (5) hazards and operating risks that may not be covered fully by
insurance, including those related to Line 6B and any additional fines and penalties assessed in connection with the crude oil release on
that line; (6) changes in or challenges to EEP’s tariff rates; and (7) changes in laws or regulations to which EEP is subject, including
compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance.
FLI regarding “drop-down” sales opportunities for our ownership in Midcoast Operating, L.P. are further qualified by the fact that Midcoast
Energy Partners, L.P. is under no obligation to buy any of our interests in Midcoast Operating, L.P., and we are under no obligation to sell
any such additional interests. As a result, we do not know when or if any such additional interests will be sold.
Our FLI is also subject to risks and uncertainties pertaining to operating performance, regulatory parameters, project approval and
support, weather, economic conditions, interest rates and commodity prices, including but not limited to those discussed more extensively
in our filings with U.S. securities regulators. The impact of any one risk, uncertainty or factor on any particular FLI is not determinable
with certainty as these are interdependent and our future course of action depends on management’s assessment of all information
available at the relevant time. Any FLI in this presentation is based only on information currently available to us and speaks only of the
date 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 and EEQ’s SEC filings, including its most recently filed Annual Report on
Form 10-K and subsequently filed Quarterly Reports on Form 10-Q.
Agenda
1. Project Update
2. MEP Drop-Down
3. Funding Outlook
4. Financial Results
5. Question & Answer
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• Line 3:
– Part of Enbridge mainline system
– Replace all remaining segments
from Hardisty to Superior with
latest available high strength
steel and coating technology
• EEP Capital Investment:
– border to Superior ~ $2.6 billion
capital
– to be joint funded with ENB
• Expected Completion:
– 2nd Half of 2017
• 30 year Cost-of-Service
– 15 year primary term
• Shipper Support (CAPP/RSG)
Line 3 Replacement
4
Montreal Gretna
Regina
Hardisty
Kerrobert
Toledo
Buffalo
Edmonton
Houston
Fort McMurray
Cromer
Cushing
Patoka
Chicago/ Flanagan
Sarnia
Superior
Port Arthur
5
Market Access Programs
Westover
+600
kbpd
+300
kbpd
+440
kbpd
+80
kbpd
+320 kpbd
2013
• Bakken Pipeline Expansion+ Berthold Rail - EEP
• Line 5 Expansion (+50 kbpd) - EEP
• Line 62 Expansion (+105 kbpd) - EEP
• Line 9A Reversal (+50 kbpd) - ENB
• Toledo Pipeline Partial Twin (+80 kbpd) - ENB
• Seaway Pipeline Expansion (+400 kbpd) - ENB
2014
• Line 6B Replacement (+260 kbpd) - EEP
• Line 67 (+120 kbpd) (1)- EEP
• Line 61 (+160 kbpd) - EEP
• Line 9B Reversal + Expansion (+320 kbpd) - ENB
• Flanagan South Pipeline (+600 kbpd) - ENB
• Seaway Twin + Lateral (+450 kbpd) - ENB
2015
• Line 67 (+230 kbpd) – 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
Organic Growth Projects:
Commercially secured
Low risk framework
Long-term contracts
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Project Execution – 2014 In-Service
Eastern Access: Ln 6B Replacement
• 160 miles of Line 6B replacement is
on target to enter service in May
• ROW and permitting for the
remaining 50 mile replacement
secured, construction to begin this
spring for Q3 2014 in service date
• ~$2.1 billion capital
Mainline Expansions
• Line 61- expansion from 400kbpd to
560kbpd between Superior and
Flanagan (3Q 2014 in-service)
• ~$0.2 billion capital
* Jointly funded 25% EEP / 75% ENB
Commercially Secured
30 year Cost of Service
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Commercial Structure & Risk Profile
Crude oil projects progressively transform EEP to lower risk business model
Cost of Service/Take-or-Pay: Contribution from Liquids and Natural Gas business cost of service and take-or-pay contracts.
Fee-based: Contribution from Liquids and Natural Gas business fee-based service. Commodity Sensitive: Contribution from Natural Gas business from its commodities length (before hedging).
Contribution is based on revenues from Liquids segment and gross margin from Natural Gas segment, excluding non-controlling interest.
Assumes Natural Gas business dropped down to MEP within five years.
0.0%
20.0%
40.0%
60.0%
80.0%
100.0%
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)
Execute Drop-Down to MEP Mid-Year Drop-Downs Bolster Funding Program
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Pa
st
Sta
te
Cu
rre
nt
Sta
te
Ne
ar
Te
rm
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 targeted mid-2014 (~$300–$400 million)
• Drop-down remaining interests in gas business to MEP within
five years
Gas-Focused Operations Liquids-Focused Operations
Funding Plan 2014-2017 (unconsolidated)
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Debt
Total Requirement 2.4
2014 – 2017 Maturities 0.9
Debt Requirement 3.3
Equity
Total Requirement 1.2
EEQ PIK (0.6)
Equity Requirement 0.6
Financing Options
Additional MEP Drop-Downs
Bank Credit Facility
Floating Rate Note
Term Debt
Hybrid Securities
Additional MEP Drop-Downs
Hybrid Securities
Private Placement
ATM program
EEP/EEQ Common Unit Offering
Uses/(Sources)
Secured Growth Capital 9.4
Maintenance Capital 0.4
Joint Funding Call Back on Lakehead Expansions 0.7
10.5
ENB Joint Funding* (3.3)
Sandpiper Joint Funding (1.0)
MEP Drop-Downs +/- (2.6)
Net Funding Required 3.6
Equity funding requirements manageable
($billion)
* Joint funding with Enbridge Inc. includes estimated 50% funding by Enbridge Inc. for U.S. component of Line 3
Replacement program and 50% estimated funding by EEP. Participation levels being finalized and approved by
Independent Special Committee.
Financial Summary
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($millions, except per unit amounts ) 1Q 2014 1Q 2013
Adjusted EBITDA1 $338.7 $281.0
Adjusted Net Income2 $102.9 $95.7
Adjusted Net Income per unit2 $0.20 $0.21
Unaudited; adjusted results exclude the impact of non-cash, mark-to-market net gains and losses; among other adjustments. Refer to the Non-GAAP Reconciliation tables presented
in the supplemental slides. 1Adjusted EBITDA includes non-controlling interest. 2Adjusted net income after non-controlling interest and deferred distribution attributable to preferred unitholders. Preferred units deferred distribution of $22.5 million in 1Q 2014.
Financial Results
As-declared Coverage Ratio *
0.89x
0.79x
1.07x 0.92x
0.00x
0.20x
0.40x
0.60x
0.80x
1.00x
2014 2013
Cash coverage
Coverage including PIK distribution * Coverage metric excludes deferred distribution attributable to preferred unitholders.
First Quarter 2014 Highlights
Strong Lakehead System Deliveries
Strong North Dakota System
Deliveries
Full quarter contributions from
growth projects
Bakken Pipeline expansion
Bakken Berthold Rail
Bakken Access
Lakehead system expansions
Strengthening Distribution
Coverage
Liquids Segment Results
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1.84 1.68
1.83 1.92 2.00
0.22
0.17
0.22 0.20
0.21 0.13
0.15
0.21 0.20
0.25
-
0.50
1.00
1.50
2.00
2.50
1Q13 2Q13 3Q13 4Q13 1Q14
Volu
me b
y S
yste
m (
mm
bpd)
Lakehead Mid-Continent North Dakota
154.3
167.9
150.2
185.8
205.2
0
50
100
150
200
1Q13 2Q13 3Q13 4Q13 1Q14
$ m
illio
ns
Adjusted Operating Income Volumes
Unaudited; adjusted results exclude the impact of: (a) additional environmental costs, net of insurance recoveries, associated with the incident on Line 6B; and (b) non-cash, mark-to-
market net gains and losses; among other adjustments. Refer to the Non-GAAP Reconciliation tables presented in the supplemental slides.
Natural Gas Segment
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26.8
15.7 16.8
4.4
8.8
0
10
20
30
40
50
1Q13 2Q13 3Q13 4Q13 1Q14
$ m
illio
ns
Unaudited; adjusted results exclude the impact of: (a) non-cash, mark-to-market net gains and losses; among other adjustments. Refer to the Non-GAAP Reconciliation tables
presented in the supplemental slides.
Adjusted Operating Income * Volumes / Rig Count
964 972 957 902 824
1,252 1,211 1,120 1,028 971
332 333 314
292 272
-
50
100
150
200
250
300
350
400
-
500
1,000
1,500
2,000
2,500
3,000
1Q13 2Q13 3Q13 4Q13 1Q14
Avera
ge R
ig C
ount
EE
P M
ain
Regio
ns
Vo
lum
e b
y S
yste
m
(mm
btu
/d in
th
ou
sa
nd
s)
Anadarko East Texas North Texas Rig Count
* During the first quarter of 2014, the Partnership changed its reporting segments. The Marketing segment was
combined with the Natural Gas segment to form one new segment called “Natural Gas”.
0
20,000
40,000
60,000
80,000
100,000
1Q13 2Q13 3Q13 4Q13 1Q14
NG
L P
rod
ucti
on
(b
pd
)
NGL Production attributable
to lost customer
Forecasted Capital Expenditures
Capital Expenditures
1 Eastern Access and US Mainline Expansion capital expenditures are forecasted net of joint funding, with assumed Enbridge Inc. 75% funding; Sandpiper capital
expenditures are forecasted net of 37.5% joint funding from Marathon Petroleum Corp. 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 base 61% funding by EEP and 39% by MEP.
Eastern Access1 265
US Mainline Expansions1 210
Sandpiper1 260
Line 6B 75-mile Replacement 15
Line 3 Replacement 100
Liquids Integrity 280
Liquids Other Growth Enhancements 260
Beckville Gas Processing Plant2 65
NG Other Growth Enhancements2 135
Core Maintenance2 $110
Total $1,700
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2,345
2,798
89
160
0
500
1,000
1,500
2,000
2,500
3,000
3/31/2014 12/31/2013
$ m
illio
ns
Credit Facilities Cash
$2,434
$2,958
Available Liquidity*
Strong investment grade credit profile (BBB/Baa2)
*EEP’s available liquidity excludes credit available to its affiliates MEP and MOLP under
their credit agreement and also excludes MEP’s cash balance at period end.
Key Takeaways
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• Strong Lakehead and North Dakota system deliveries
• Coverage continues to strengthen as organic growth
projects enter service
• Target first drop-down post-IPO to MEP mid-2014
• Manageable funding plan – minimal equity requirements
• Secured Liquids projects collectively further transform
the Partnership to an even lower risk business model
• Distribution growth: targeting 2% to 5% annual growth
Safety and operational reliability are cornerstones that underpin
our business and growth outlook