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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 of this presentation. 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.
Investment Highlights
3
*Enterprise Value as of 4/30/14; **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
Investment Proposition
4
65% 62%
19%
• Owner and operator of largest crude
oil pipeline system
• ~$40 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
organic growth program underway
Strength of GP – Enbridge Inc.
5
ENB: North American leader in
energy delivery
Strategic Position
6
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
2013 Enbridge Forecast 2013 Enbridge Upside Forecast Optimal Pipeline Capacity
Supply Forecast
WCSB Supply Forecast vs. Pipeline
Takeaway Capacity*
7
*Includes Bakken entering ENB Mainline ex-Superior Sources: Enbridge Internal Forecast
Keystone XL
ENB Northern Gateway
TransMountain Expansion
Energy East
8
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
North American Crude Oil Price
Fundamentals
9
$114
$111
$96
Alberta Light
Bakken
Brent
Maya
Asia
$96
$104
LLS
WCS
$97
$84
$102
Light Crude
Heavy Crude
$104
WTI
Light Differentials
Brent – WTI $9
LLS – WTI $2
Asia – WTI $12
WTI – Bakken $5
WTI - Alberta
Light
$6
Heavy Differentials
Maya – WCS $12
Asia – WCS $20
Significant Infrastructure Investment Opportunities
May 14, 2014 prices (in US$/bbl)
North American Supply
North American Demand
Transportation Bottlenecks
Volatile Price Differentials
10
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
Montreal Gretna
Regina
Hardisty
Kerrobert
Toledo
Buffalo
Edmonton
Houston
Fort McMurray
Cromer
Cushing
Patoka
Chicago/ Flanagan
Sarnia
Superior
Port Arthur
Market Access Programs
11
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) - 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 (+70 kbpd) - EEP
Market Access Programs Bolster Lakehead System Utilization
(1) 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
12
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
• 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
13
Bakken Expansion – Sandpiper Pipeline
Clearbrook
Superior
Sarnia
Chicago
Patoka
Toledo
Montreal
Westover
Hardisty
Cushing
Regina
Gretna
14
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
Flanagan
Midcoast Energy Partners IPO (MEP) Drop-Downs Bolster Funding Program
15
Pa
st
Sta
te
Cu
rre
nt
Sta
te
Nea
r Te
rm
EEP: ‘Pure-Play’ Liquids Pipeline MLP
MEP: ‘Pure-Play’ Natural Gas & NGL Midstream 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
EEP to Drop-Down Natural Gas & NGL
Business to MEP
IPO NTM 9/30/14 2017E
(1) Compounded annual distribution growth rate. Target annualized minimum quarterly distribution is $1.25/unit.
MEP to Execute on Growth Strategy
Attractive Distribution Growth
100%
61%
39%
First drop-down post-IPO targeted mid-2014 ~ $300–$400 million
• 100% Debt funded
Execute on actionable organic growth opportunities
Logistics & Marketing business positioned to capture commodity price
optimization
IPO 2014 2017e Natu
ral G
as b
usin
ess o
wn
ers
hip
16
Natural Gas and NGL Midstream Business
17
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
18
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%
2011 2012 2013 2014 2015 2016 2017
59%
23%
18%
Cost-of-Service/Take-or-Pay
Commodity Sensitive
Fee-Based 24%
76%
(Unconsolidated view)
Strengthening Distribution Coverage
19
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
Co
vera
ge*
* 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
Distribution Growth Target
20
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% -
Funding Plan 2014-2017 (unconsolidated)
21
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.
Long-Term ENB Liquids Drop-Down
Potential: $10 Billion +
22
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.
** 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
ownership by 15% one year after the in-service date.
~ $10B
($ Billions)
Examples:
Key Takeaways
23
• Strategic position supported by strong business fundamentals
• Secured Liquids projects collectively transform the Partnership
to an even lower risk business model
• Coverage strengthens as organic growth projects enter service
• Distribution growth: targeting 2% to 5% annual growth
• Minimal equity funding requirements
• First drop-down post-IPO to MEP mid-2014
• Strategically aligned, supportive general partner
Safety and operational reliability are cornerstones that underpin
our business and growth outlook