eep investment community presentation march 2014€¦ · this presentation includes certain forward...
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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 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.
Corporate Structure
*Ownership, as of February 14, 2014.
Yield as of February 26, 2014; EV and TSR (nominal CAGR) as of 12/31/13.
2%
General Partner
Interest
And
16.3%
Limited Partner
Interest
100% Indirectly Owned
100% Voting Shares 11.7% Listed Shares
Management
and Control
19.5% Limited Partner
Interest (I Units)
88.3%
62.2%
Enbridge Energy
Company, Inc.
Enbridge Energy
Partners, L.P. (NYSE: EEP)
Enbridge Energy
Management, L.L.C. (NYSE: EEQ)
Enbridge Inc.
(NYSE: ENB)
Public
Public
Enbridge Inc. owns
~21% of EEP
ENB*
• Yield: 3.0%
• 10-yr TSR: 17%
• EV: $66B
EEQ*
• Yield: 8.1%
• 10-yr TSR: 12%
• EV: $1.8B
EEP*
• Yield: 7.8%
• 10-yr TSR: 9%
• EV: $14.1B
3
Midcoast Energy
Partners, L.P. (NYSE: MEP)
Midcoast
Operating, L.P.
61%
Limited Partner
Interest
38.999% LP interest;
0.001% GP interest
46.0% Public
52% LP interest;
2% GP interest
MEP*
• Yield: 6.1%
Enbridge Energy Partners Factsheet
Financial Highlights
Market Cap* $11B
Yield* 7.8%
Distribution $2.17/unit annual
Total Shareholder Return (10yr CAGR) 9%
Credit Rating Investment Grade BBB/Baa2
2014 Adjusted EBITDA Guidance** $1.5 to $1.6 Billion
EEP is one of the longest serving MLPs (since 1991) and has consistently delivered cash
distributions to its unitholders
Key Assets
Liquids Deliveries of ~ 2.2 MMbpd
Transportation Pipelines 6,265 miles of pipe
Gathering Pipelines 240 miles of pipe
Storage Capacity 39.4 million barrels
Natural Gas Deliveries of ~ 2.5 bcf/d
Gathering and Transportation Pipelines 11,400 miles of pipe
Processing Capacity (26 plants) 2.3 Bcf/d
Treating Capacity (11 plants) 1.3 Bcf/d
*As of February 26,2014. ** Includes non-controlling interest estimated at $355 million.
Highlights
Strategically positioned assets:
Largest pipeline transporter of crude oil from Western Canada into the U.S.
Largest pipeline transporter of crude oil from the Bakken formation
Over $8.5 billion of organic growth secured
Cash flows secured predominantly by long-term, low risk commercial structures
4
Investment Proposition
5
Attractive Investment Proposition
* As February 26, 2014
** Return CAGR since inception (nominal)
Nusta
r
EE
P
Kin
der
Morg
an
Will
iam
s
Energ
y T
ransfe
r
Buckeye
Oneok
Pla
ins A
ll A
merican
Spectr
a P
art
ners
Ente
rprise
Magella
n M
idstr
eam
Sunoco L
ogis
tics
Bo
ard
wa
lk
FT
SE
NA
RE
IT
S&
P 5
00
Utilit
ies
10-Y
r T
reasury N
ote
s
S&
P 5
00
0%
1%
2%
3%
4%
5%
6%
7%
8%
9%
10%
Peer average: 5.6%
EEP: 7.8%
MLPs* Other Asset
Classes*
Attractive Yield • One of the longest serving pipeline MLPs (1991)
• Attractive return CAGR
• Track record of consistently delivering cash distributions
• Prudent growth
$0
$20,000
$40,000
$60,000
$80,000
$100,000
$120,000
$140,000
$160,000
$180,000
Total Shareholder Return
1991 2013
6
Distribution Growth Target
Organic growth platform supports distribution growth
2007 2008 2009 2010 2011 2012 2013 2017e
2.7% 4.2% - 3.8% 3.6% 2.1% -
7
65% 62%
19%
~$36 billion equity market cap
Strong investment grade
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
Joint funding provides
Partnership financing flexibility
Strength of GP – Enbridge Inc.
8
Strategic Position Premier asset position Crude oil pipeline and storage systems deliver ~ 2.5 million barrels/day
Natural gas gathering, processing & treating systems deliver ~ 2.5 billion cubic feet/day
EEP Liquids Pipelines
ENB Liquids Pipelines and Joint Ventures
EEP/MEP Natural Gas Pipelines
EEP/MEP NGL Pipeline Joint Venture
9
North Dakota System
Midcontinent System
Lakehead System
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
201
3-Q
1
20
14
-Q1
201
5-Q
1
201
6-Q
1
201
7-Q
1
20
18
-Q1
201
9-Q
1
202
0-Q
1
202
1-Q
1
20
22
-Q1
MMbpd
2013 Enbridge Supply Forecast 2013 Enbridge Upside Supply Forecast Optimal Pipeline Capacity
• Keystone XL
• ENB Northern Gateway
• TransMountain Expansion
• Energy East
*Includes Bakken entering ENB Mainline
10
Supply Forecast
Bakken Crude Oil Supply Forecast vs. Pipeline
Takeaway Capacity
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
MMbpd
Enbridge Bakken Expansion Program
Enbridge North Dakota system
11
Commodity Price Fundamentals Driving
Market Access Strategy
$115
$110
$92
Alberta Light
Bakken
Brent
Maya
Asia
$92
$109
LLS
WCS
$97
$79
$103
Light Crude
Heavy Crude
$105
WTI
Light Differentials
Brent – WTI $7
LLS – WTI $6
Asia – WTI $12
WTI – Bakken $6
WTI - Alberta
Light
$11
Heavy Differentials
Maya – WCS $13
Asia – WCS $26
Significant Infrastructure Investment Opportunities
February 27, 2014 prices (in US$/bbl)
North American Supply
North American Demand
Public Opposition to Infrastructure
Transportation Bottlenecks
Volatile Price Differentials
12
Montreal
Toronto
Gretna
Regina
Hardisty
Kerrobert
Superior
Toledo
Buffalo
Edmonton
Houston
Detroit
Clearbrook
Flanagan
Fort McMurray
Cromer
Cushing
Patoka
Chicago
Wood River
Sarnia
Enbridge Inc. Enbridge Energy Partners L.P.
Strategic Position Crude Oil Transportation
Competitive Advantages:
• Scale: 2.5 million bpd
• Connected to rapidly growing
supply sources
• Market diversity
• Access to premium markets
• Well positioned for extension to
new markets
• Established ROW
• Multiple lines: quality/reliability
13
Providing New Market Access
14
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
EEP Lakehead & North Dakota
Systems
Montreal Gretna
Regina
Hardisty
Kerrobert
Toledo
Buffalo
Edmonton
Houston
Fort McMurray
Cromer
Cushing
Patoka
Chicago/ Flanagan
Sarnia
Superior
Port Arthur
Market Access Programs
15
Westover
+600
kbpd
+300
kbpd
+440
kbpd
+80
kbpd
+300 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 (+300 kbpd) - ENB
• Flanagan South Pipeline (+585 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 (+75 kbpd) - EEP
Market Access Programs Bolster Lakehead System Utilization
EEP Lakehead &
North Dakota systems
2014 EEP Project In-Service:
Mainline Expansion(1) ~$0.2B
capital (3Q)
Line 6B Replacement ~$1.7B
capital (1Q/3Q)
(1) Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions.
Placed $1.2B assets in-service during 2013
Bakken Expansion – Sandpiper Pipeline
Clearbrook
Sarnia
Patoka
Toledo
Montreal
Westover
Hardisty
Cushing
Sandpiper Pipeline
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
Regina
Gretna
Chicago Flanagan
16
Natural Gas and NGL Midstream Business
Anadarko System Ajax Processing Plant in service 3Q 2013
Texas Express NGL System In service 4Q 2013
North Texas System
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
17
Business Opportunities – Natural Gas
and NGL Midstream
EAGLEBINE
CLINE SHALE
• Accretive growth • Capture rich gas processing opportunities • New pipeline laterals, NGL laterals, and
compression projects • Increase processing capabilities
• System optimization • Pursue accretive acquisitions
• Extend geographic reach • Complement and diversify existing asset footprint
• Enhance end-market access • Expand condensate treating, stabilization,
and liquids takeaway • Pursue vertical integration opportunities • Specialty services for off-spec products
Gathering, Processing & Transportation Logistics & Marketing
COTTON VALLEY
Optimize Asset and Commodity
Value
Market Origination
& Downstream
Pathing
Bundled Service Offering
Risk Management
Gathering, Processing &
Transportation
Natural Gas Marketing
Condensate Marketing
NGL Logistics & Marketing
Operational Reliability & Project Execution
19
Industry Leadership
Integrity Management
Leak Detection Capability and
Control Systems
Third Party Damage Avoidance and
Detection
Incident Response Capacity
Employee and Contractor
Occupational Safety
Public Safety and Environmental
Protection
Organizational commitment to being “best in class”
Operational
Reliability
Project
Execution
Project
Development
Proven track record: on-time & on-budget
Supply Chain
Management
Construction
Experience
Life Cycle
Gating Control
Regulatory &
Permitting
Major
Projects
Business Mix & Risk Profile
20
Liquids Pipelines
~90%
Natural Gas
~10%
Operating Income*
0%
20%
40%
60%
80%
100%
2008 2009 2010 2011 2012 2013 2014 2015 2016
60%
12%
18%
59%
23%
28%
Commodity
Fee-Based
Cost of Service /
Take-or-Pay
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, including non-controlling interest.
*Note: based on 2014 forecast (consolidated basis)
Delivering Low-Risk Sustainable Growth
21
(1) Eastern Access and Mainline Expansion liquids expansion projects jointly funded by EEP & ENB. 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
Expected Project In-Service Period 1H13 2H13 1H14 2H14 1H15 2H15 1H16
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
Natural Gas Projects (2)
Ajax Plant
Texas Express NGL Pipeline JV
Beckville Plant
Distribution coverage strengthens as growth projects enter service
Midcoast Energy Partners IPO
Gas & Liquids Operations
Gas-Focused Operations Liquids-Focused Operations
Enhances Strategic Focus of Each Partnership
Dual Funding Sources to Support Growth
Creates Drop-Down Opportunity for MEP
Pa
st
Sta
te
Cu
rre
nt
Sta
te
22
Near-term Actions
1st Drop-Down post-IPO mid-2014 (~$300 – $500mm)
Drop-down remaining interests in gas business
to MEP within five years Nea
r Te
rm
Executing on our Financing Plan
23
Enhanced financing flexibility
Matches timing of permanent
funding with project cash flows
Strengthens credit metrics
Supportive general partner
MEP provides additional source
of capital through drop-downs
$1.2 Billion Preferred Unit Private
Placement
Exercise Joint Funding Option +$720MM
Accounts Receivable Sale
EEQ public offering +$500MM
Upsized credit facilities +$525MM
Midcoast Energy Partners IPO +$675MM*
Sandpiper JV with Marathon +$975MM
2013 Financing Actions
Manageable funding outlook
*Proceeds distributed to EEP from the MEP IPO include net proceeds from the public offering , in addition to proceeds from the overallotment exercise, plus MEP borrowings, less fees associated with the revolving credit facility and working capital agreement.
Funding Plan 2014-2017 (unconsolidated)
Debt
Total Requirement 1.2
2014 – 2017 Maturities 0.9
Debt Requirement 2.1
Equity
Total Requirement 1.2
EEQ PIK 0.6
Equity Requirement 0.6
24
Financing Options
Bank Credit Facility
Floating Rate Note
Term Debt
Hybrid Securities
Additional MEP Drop-Downs
Hybrid Securities
Private Placement
ATM program
EEP/EEQ Common Unit Offering
Uses/(Sources)
Secured Growth Capital 7.0
Maintenance Capital 0.4
Joint Funding Call Back on Lakehead Expansions 0.7
8.1
ENB Joint Funding (2.1)
Sandpiper Joint Funding (1.0)
MEP Drop-Downs +/- (2.6)
Net Funding Required 2.4
Equity funding requirements minimal; capacity for further growth investment
($billion)
Key Takeaways
25
• Top priorities: system integrity, safety and project execution
• Liquids growth projects collectively transform the
Partnership to lower risk business model
• Minimal equity funding requirements
• First drop-down post-IPO to MEP mid-2014
• Coverage strengthens as organic growth projects enter
service
• Distribution growth: targeting 2% to 5% annual growth
• Supportive general partner
Financial Outlook 2014
*Adjusted EBITDA inclusive of non-controlling interest and other income. EBITDA from non-controlling interest
estimated at $355 million, which is inclusive of ~$30 million of other income associated with AEDC.
**Depreciation includes non-controlling interest component of ~104 million.
Earnings Outlook 2014
1,500
1,050
440
1,600
1,130
480
0
200
400
600
800
1,000
1,200
1,400
1,600
Adjusted EBITDA* AdjustedOperating Income
Depreciation**
$ m
illio
ns
Guidance Range
Available Liquidity
27
500
1,000
1,500
2011 2012 2013 2014e
$ m
illio
ns
Liquids Projects Deliver EBITDA Growth
Based on adjusted EBITDA.
Coverage 0.85x-0.95x; Cash Coverage 1.05-1.15x
2,463
165
0
500
1,000
1,500
2,000
2,500
12/31/2013
$ m
illio
ns
Credit Facilities Cash
$2,628
Volume Assumptions
28
Liquids Volumes (kpbd)
2013 2014e
Lakehead 1,816 2,000– 2,200
North Dakota (1) 236 326 – 346
Mid-Continent 201 200 – 220
Total 2,253 2,526 – 2,766
Natural Gas Volumes (Mmbtu/d)
NGL Production (Bpd)
2013 2014e
Anadarko 949 850 – 900
East Texas 1,153 1,100 – 1,200
North Texas 317 300 – 320
Total 2,419 2,250 – 2,420
2013 2014e
88,346 88,000 – 92,000
Liquids Organic Growth Projects Bolster System Utilization
(1) North Dakota system volumes include physical volumes on North Dakota Trunkline and ship-or-pay volumes on Bakken Expansion. (2013: physical 171
kpbd; 2014 forecasted physical volumes range 230 - 250 kbpd)
Robust Western Canadian supply growth Strong downstream refining demand Liquids projects in-service
Growing Lakehead system deliveries forecast
Delivering Prudent Growth
29
(1) Eastern Access and Mainline Expansion Liquids projects to be jointly funded by EEP & ENB. Sandpiper construction to be funded 37.5% by Marathon Petroleum Corp. (2) Eastern Access has modest capital cost risk (3) Assumed capex is proportionally funded based on 61% current EEP ownership. (4) Line 67 in-service delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions.
($MM) Growth Capital
Net Capital EEP
Target In-Service Risk Profile
Bakken Growth Projects
Bakken Expansion 300 300 1Q13 10 year ship-or-pay
Bakken Rail 145 145 1Q13 3 year ship-or-pay
Bakken Access 100 100 2Q/3Q13 Volume Risk
Sandpiper (1) 2,600 1,625 early 2016
Sandpiper:
Ship-or-pay/Cost of Service
Eastern Access &
Mainline Expansions
30 year Cost of Service
No volume risk
No capital risk (2)
Eastern Access (1)
Line 6B Replacement, Line 5,
Line 62 expansion 2,100 525 2Q 2013 – 2014
Line 6B Expansion + tankage 400 100 early 2016
US Mainline Expansion (1)
Line 67 (Border to Superior) (4)
Line 61 (Superior to Flanagan) 1,900 475
Phase 1 3Q14;
Phase 2 2015-2016
Chicago Connectivity (Line 62 twin) 500 125 2H 2015
Ajax Plant 230 230 4Q13 Commodity & volume risk
Texas Express NGL Pipeline 400 400 4Q13 10 year ship-or-pay; with additional
5 year dedication
Beckville Plant(3) 145 88 2015 Commodity & volume risk
$8,820 $4,113
Organic growth secured by long-term low risk commercial structures
Liq
uid
s
Ga
s
Bakken Expansion Program
Clearbrook
Gretna
Saskatchewan
Enbridge Mainline System
North Dakota System
Bakken Expansion Project
Saskatchewan System (ENF)
Bakken Access Program
Sandpiper Pipeline
Minot
Lignite
Weyburn
Cromer
Berthold
Steelman
Tioga Stanley
Alliance Pipeline
Regional Pipeline Takeaway:
• EEP North Dakota Pipeline Capacity
• 210 kbpd current
• Bakken Expansion +145 kbpd (1Q13)
• Sandpiper Project (2016)
• + 225 kbpd to Clearbrook
• + 375 kbpd Clearbrook to Superior
Regional Rail Takeaway & Delivery
• Bakken Berthold Rail +80 kbpd (1Q13)
• Philadelphia Rail JV + 80 kbpd (4Q13)
Regional Gathering
• Bakken Access +100 kbpd (3Q13)
Berthold Rail Program
EEP pipeline takeaway will reach 580 kbpd with next phase of expansion
Capital = $3.1B
to Superior
Growth Projects:
Commercially secured
Low-risk framework
Long-term contracts
30
Eastern Access Growth Projects
31
Clearbrook
Superior
Sarnia
Chicago
Patoka
Toledo
Montreal
Westover
3
1
4
5
Cushing
EEP/ENB joint funded
ENB
EEP Eastern Access Projects ($2.5B)
Line 5 Expansion (2Q13)
• +50 kbpd capacity increase into Sarnia (540 kbpd total)
Spearhead North Expansion (4Q13)
• +105 kbpd capacity increase into Chicago (235 kbpd total)
Line 6B Replacement & Expansion (2014 to early 2016)
• +260 kbpd capacity expansion into Sarnia (500 kbpd total)
• +70 kbpd capacity expansion Griffith to Stockbridge
• Breakout tankage
EEP US Mainline Expansion Project ($0.5B)
Chicago Connectivity - Spearhead North Twin (2H 2015)
• +570 bpd capacity increase into Chicago
EEP/ENB joint funded
1
2
2
3
5
Flanagan
Linking North American crude supply growth to eastern refining centers
Growth Projects:
Commercially secured
Low-risk framework
Long-term contracts
Refining center
2
Enbridge Inc. Expansions ($0.6B)
Toledo Pipeline Partial Twin (2013)
• +100 kbpd access to Michigan & Ohio refineries (180 kbpd)
Line 9 Reversal (2013/2014)
• 240 kbpd reversal to access refineries in Ontario & Quebec
• 80 kbpd expansion
4
5
31
Western U.S. Gulf Coast Access
32
Cushing
Houston
Chicago/ Flanagan
Port Arthur
1
3
2 Enbridge Inc. Projects ($5.2B)
Seaway Pipeline
• Enbridge Inc. and Enterprise JV
• current capacity up to 400 kbpd
Flanagan South Pipeline
• Initial capacity 585 kbpd (36” line)
• 100% ENB; in-service mid-2014
Seaway Pipeline Twin & Lateral
• Enbridge Inc. and Enterprise JV
• Initial capacity 450k bpd; 30’’ line
• In-service 1H 2014
1
2
3
EEP US Mainline Expansion ($1.9B)
Line 67 Expansion
• +350 kbpd capacity increase to 800 kbpd
• expanded to full hydraulic capacity
Line 61 Expansion
• +800 kbpd capacity increase to 1,200 kbpd
• expanded to full hydraulic capacity
Phase 1 3Q14; Phase 2 2015-2016
EEP/ENB joint funded
No pipe construction required
5
4 4
5
Growth Projects:
Commercially secured
Low-risk framework
Long-term contracts
Refining center
Linking North American crude supply growth to USGC refining centers
Heavy 43% Light
57%
Western USGC Refining Processing Capability
Source: EIA and Enbridge’s internal estimates
W USGC ~ 4,400 kbpd
32
North American Crude Oil Supply Growth
(2013 – 2025)
33
Bakken
Eagle Ford
Permian Basin
Other
Niobrara
Oil Sands
0.0
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Heavy Light
Cardium, Viking, Duvernay
Sources: Enbridge Internal Forecast and External Forecasts
+ 7 MMbpd by 2025
MMbpd
North American Crude Oil Demand
34 Source: StatsCan, EIA, Enbridge Internal Forecasts
Light Markets
• East Coast
• Eastern PADD II
• PADD III
Heavy Markets
• PADD II
• PADD III 34
Impact of Line 6B Incident
35
As of September
30, 2013
Booked in Q4
2013Total to Date
Total Costs $1,035 $87 $1,122
Less: Insurance Recoveries $547 $0 $547
Total Normalized $488 $87 $575
Estimated Costs*
*Includes $29.6 million in fines and penalties associated with the Line 6B incident. Due to the absence of sufficient
information, we cannot provide a reasonable estimate of our liability for additional fines and penalties that could be
assessed in connection of the Line 6B incident. As a result, except for the penalties disclosed herein, we have not
recorded any liability for expected fines and penalties.
Unaudited amounts, $ in millions. Represents life-to-date amounts pursuant to impact of the Line 6B incident.
Major Canadian and US Crude Oil Pipelines and
Refineries
36
36
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