enbridge energy partners, l.p./media/eepeeqmep/events/eepeeq/20… · risk profile 1991 apr 2016...
TRANSCRIPT
Enbridge Energy Partners, L.P.
June 1-3, 2016
MLPA Investor Conference
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) changes in or challenges to the Partnership’s tariff rates; (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; and (8) 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
~$16B* Enterprise Value
Large-Cap MLP
BBB, Baa3, BBB Strong Investment Grade &
Stable Outlook
(S&P, Moody’s, DBRS)
*Market capitalization and yield as of 5/20/16; **Return CAGR since inception to 4/29/2016 (nominal)
Pure-Play Liquids
Pipeline MLP Low-risk Growth Underway
Utility-like MLP Defensive cash flow
risk profile
Apr 2016 1991
Ticker Symbol NYSE: EEP
Market Capitalization* $10.6 Billion
Yield* 10.6%
Current Cash Distribution $2.332/unit annual
Total Unitholder Return
(CAGR since inception)** 11%
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
1Commodity sensitive gross margin forecast is before hedging; greater than 90% of 2016e commodity sensitive cash flows are hedged substantially above current market prices. 2EEP 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
Strong Western Canadian Supply Outlook and Demand for Pipeline Capacity
U.S. Mainline oversubscribed; Q1 2016 deliveries +15% vs. prior quarter
~800 kbpd oil sands supply growth through 2019
Basin short >500 kbpd pipeline capacity by 2021
0
0.5
1
1.5
2
2.5
3
Q22014
Q32014
Q42014
Q12015
Q22015
Q32015
Q42015
Q12016
Lakehead Deliveries MMBPD
Oil Sands Growth Pipeline Capacity vs. WCSB Supply
SLIDE 5
CAPP Crude Oil Forecast, Markets and Transportation
(June 2015 Operating & In Construction)
Western Canadian Supply Profile vs. Crude Price
SLIDE 8
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 $26 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
2015 Projects
EEP Project
ENB Project
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 distribution 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 + 2.65%(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% expiries 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 + 2.65%(1)
Mid-Continent System: toll indexed to PPI + 2.65%(1)
years
(1) FERC index annual adjustment of PPI + 1.23%. (prior index adjustment of PPI + 2.65% expiries June 30, 2016).
(2) 30 year cost of service agreement, with 15 year initial term.
Lakehead base toll indexed to PPI + 2.65%(1)
Co
st-
of-
Serv
ice
F
ee
-ba
sed
(2)
Foundation for Delivering Sustainable Growth
SLIDE 12
Premier MLP Sponsor: Enbridge Inc. (ENB)
Note: Standard & Poor’s/Moody’s credit ratings respectively.
Market capitalization in USD as of 5/20/2016
ENB: A leader in energy delivery
• Owner and operator of largest crude oil pipeline
system
• ~$37 billion equity market cap
• Strong investment grade (BBB+, Baa2)
• Proven track record: industry leading EPS and
DPS growth
• 13% 10-year TSR CAGR
• 13% 10-year DPS CAGR
• 10% - 12% DPS growth forecast 2016-2019
• Strategy aligned with Partnership
• ~$26 billion enterprise-wide secured organic
growth program underway
Wind
Solar
Gas Distribution
Storage
Liquids Pipelines
Gas Pipelines
Three Pillars of Growth
SLIDE 13
Diversified growth platform
Drop-downs
from Sponsor
EEP
• 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 2017: +1.0MMbpd of Heavy; +0.7MMbpd of Light
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
SLIDE 15
Well positioned to pursue additional expansions to meet shipper needs; phased expansions are attractive in a low crude price environment
1
2 3 4
1
2
1
2
2
3
Market Access Opportunities kbpd
1 Eastern Gulf Coast Access 350+
2 Flanagan South / Seaway Expansions 200
3 Line 9 Expansion 70
Ex-Superior Expansion Opportunities kbpd
1 Line 61 Twin 550+
2 SAX Expansion 150
Upstream of Superior Expansion Opportunities kbpd
1 Sandpiper Expansion/
Bakken Interconnect Idle 170
2 Line 2A/LSR Expansion 100
3 Line 2B/4 Capacity Recovery 150
4 Line 3 at 760 370
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
0
1,000
2,000
3,000
4,000
5,000
6,000
2015 2017 2019 2021 2023 2025
kbpd
Total Conventional Upgraded Light (Synthetic) Oil Sands Heavy CAPP O & C
WCSB Crude Supply Forecast
SLIDE 18
Western Canadian producers have a long-term investment horizon
Source: CAPP – Crude Oil Forecast, Markets and Pipelines (June 2015)
• Incremental economics of
projects in construction
• Long-term price views
• Synergies with existing
operations
• Cost reductions
• Integrated Operations
Pipeline Capacity vs. Supply Outlook
SLIDE 19
Strong demand for pipeline takeaway capacity out of Western Canada
Source: CAPP – Crude Oil Forecast, Markets and Pipelines (June 2015)
Regina Deliveries
Western Canadian Refineries
supply outlook
0
1
2
3
4
5
6
7
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
MMbpd
Enbridge
Regina Deliveries
Other Existing Pipelines
Western Canadian Refineries
CAPP 2015 CAPP 2015 Operating & Construction Only
“Kearl bitumen production averaged
203,000 barrels per day in the quarter (144,000 barrels Imperial’s share).
Production was up 137,000 barrels (97,000 barrels Imperial's share) from
the fourth quarter of 2014, and up 22,000 barrels (16,000 barrels
Imperial's share) from the third quarter of 2015. The increase was largely
due to continued strong performance from the expansion project and
optimization efforts at the combined Kearl operation”
Imperial Oil Q4 Earnings release Feb 2, 2016
“Production at Sunrise Energy Project is
increasing as expected, with recent peak gross volumes of more than
25,000 bbls/day compared to 13,000-14,000 in late October. The plan
provides for a steady and deliberate ramp up towards full capacity of
60,000 barrels per day around the end of 2016.”
Husky Energy 4th Quarter Results Release Feb 26, 2016
“ConocoPhillips safely delivered first oil at its Surmont 2 in-situ oil sands
facility in Canada. Production will ramp-up through 2017, adding
approximately 118,000 barrels per day gross capacity.”
ConocoPhillips News Release Sept 1, 2015
“The Fort Hills project remains on schedule with construction more than
50% complete at the end of the fourth quarter (2015).”
Suncor Energy Inc. 4th Quarter 2015 Results Feb 3, 2016
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
$-
$10
$20
$30
$40
$50
$60
McKenzie Dunn Mountrail Williams
US
D/b
bl
Estimated Breakeven in Core Counties (based on IRR of 10%)
24-month WTI USD/bbl Source: Enbridge estimates and North Dakota DMR data
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
kb
pd
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 - $8
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
Production growth with limited
alternative takeaway capacity ❶
CAPACITY
(kbpd)
Mainline Connected Refineries 1,900
Mainline Connected Markets (Pipeline Access) 1,575
Total 3,475
Strong demand from refineries
and connected markets❸
EEP Lakehead System
matches supply and demand 2
Liquids Pipelines Organic
Growth Underway
Bakken Expansion – Sandpiper Pipeline
SLIDE 24
EEP pipeline takeaway will reach 580,000 bpd with next phase of expansion
Total Secured Capital =
$2.6 B
• Sandpiper is expandable by 170
kbpd through horsepower upgrades
• Low risk framework
(ship-or-pay/cost-of-service)
• Marathon Petroleum is anchor
shipper
• Sandpiper provides access to
premium PADD II market
Scope 600 mile, 24”/30” pipeline
Capacity ~225 kbpd/375kbpd
Target
In-Service Early 2019
Marathon
Funding
37.5% of construction for
~27% equity interest in EEP
ND system
Line 3 Replacement
SLIDE 25
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)
Sandpiper and Line 3 Replacement Projects
MPUC Regulatory Timeline Clarified
• Certificate of Need/Route Permit processes rejoined
• EIS to precede evidentiary phase; EIS process underway
• Expected in-service early 2019
SLIDE 26
Early 2019 in-service; reduced near-term capital requirements
Line 3
Sandpiper
Financial Outlook
and Risk Management
Funding Outlook
Manageable funding needs
• Significantly reduced 2016 capital expenditures, ~$920MM
• Based on liquidity position and combined with current equity valuation, do not expect to access equity market in 2016
Joint Funding with sponsor enhances financial flexibility
• Line 3 Replacement project joint-funding levels being reviewed and not yet determined
Credit metrics and distribution coverage strengthen as projects enter service
• Cost of service and take-or-pay structures to deliver highly certain cash flow growth
Maintaining investment grade rating remains a priority
SLIDE 28
Delivering Prudent Growth
SLIDE 29
Manageable funding outlook; joint funding with sponsor enhances financial flexibility
(1) Eastern Access and Mainline Expansion Liquids projects to be jointly funded 75% by ENB and 25% by EEP. Sandpiper construction to be funded 37.5% by Marathon Petroleum Corp. (2) Joint funding with Enbridge assumes estimated 50% funding by Enbridge for U.S. component of Line 3 Replacement project and 50% estimated funding by EEP. Participation levels under consideration
by Independent Special Committee and have not been determined.
Liquids Pipelines(1)
($mm)
Growth
Capital
Net Capital
EEP
Target
In-Service
Risk Profile
Eastern Access
30 Year Cost of Service
• No Volume Risk
• No Capital Risk
Line 6B Expansion
+ Tankage $310 $78 Mid-2016
US Mainline Expansion
Line 61
(additional tankage) $380 $95 3Q15-3Q16
Line 61
(expansion to 1.2 MMbpd) $485 $121 Early 2019
Line 3 Replacement $2,600 $1,300 Early 2019
Sandpiper Pipeline $2,600 $1,625 Early 2019 Long-term Ship-or-Pay
$6,375 $3,219
($mm)
Liquids Pipeline(1)
Growth
Capital
Net Capital
EEP
Target
In-Service Risk Profile
Eastern Access
• 30 year Cost of
Service
• No Volume Risk
• No Capital Risk
Line 6B Expansion + tankage $310 $78 Mid - 2016
US Mainline Expansion
Line 61 (additional tankage) $380 $95 3Q15-3Q16
Line 61 (expansion to 1.2 MMbpd) $485 $121 Early 2019
Line 3 Replacement (2) $2,600 $1,300 Early 2019
Sandpiper Pipeline $2,600 $1,625 Early 2019 Long-term Ship-or -
Pay/Cost of Service
$6,375 $3,219
Natural Gas Segment
SLIDE 30
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 31
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 BBB/Baa2
Shipper 6: Refiner AA-/A1
Shipper 7: Integrated A+/Aa2
Shipper 8: Midstream BBB/Baa2
Shipper 9: Refiner Credit enhancement to investment grade
Shipper 10: Refiner Credit enhancement to investment grade
Investment Grade Non-Investment Grade
Priority One – Focus on Safety & Operational Reliability
SLIDE 32
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 33
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
• Long-term distribution growth target of 2 to 5%, once major projects enter service
Premier MLP sponsor • Enbridge Inc. strategically aligned with the Partnership
Appendix
Enbridge Energy Partners, L.P.
Investment Community Presentation
May 2016
Corporate Structure
SLIDE 35
Corporate structure as of May 13, 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)
Capital and Investment Expenditures
SLIDE 36
Sufficient liquidity to fund base capital program; not expecting to access equity market in 2016
2016 CAPITAL AND INVESTMENT EXPENDITURES
($ millions)
Eastern Access1 50
US Mainline Expansions1 70
Sandpiper1 80
Line 3 Replacement 180
Liquids Integrity 270
Liquids Other Growth Enhancements 190
Natural Gas Growth Projects2 20
Maintenance Capital Expenditures2 60
Total Capital Expenditures 920
Eastern Access call option exercise 360
Line 3 Replacement joint funding scenario3 (~350)
Capital and Investment Expenditures +/- 920
646
87
0
250
500
750
1,000
3/31/2016
Credit Facilities Cash
$733
Available Liquidity ($ 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.
Preferred Unit Restructuring
SLIDE 37
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
North American Crude Oil Pricing Differentials
SLIDE 38
Enbridge is the low cost transportation provider and we will continue to grow our pipeline systems
Heavy Crude
Light Crude
$41*
$51
$52*
$50
$42* 1 –May 25, 2016 pricing (Crude Prices: USD/bbl)
* represents landed price.
Pacific Alberta Light
WCS
Bakken Light
WTI
Maya
Brent
$49
$49
$48
$38
LLS
$48*
ANS
Differentials
Current (1)
WCS – Maya (4)
WCS – West Coast Heavy (3)
Alberta Light – WTI (1)
Alberta Light – Brent* (4)
Bakken – LLS (2)
Bakken – ANS 1
Bakken Infrastructure
SLIDE 39
Largest pipeline transporter of crude oil from the Bakken region to premium markets
*Marathon Petroleum Corp. will fund 37.5% of Project Sandpiper cost and assume a ~27% equity interest in the
EEP North Dakota system, once the project enters service. Sandpiper target in-service date of early 2019.
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% expiries June 30, 2016).
System Regulatory Methodology
Lakehead System Base Toll Toll Indexed to PPI + 2.65%
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 + 2.65% (Fall back is cost of service(1))
Phase V-VI Expansion Cost of Service
Mid-Continent Toll Indexed to PPI + 2.65% (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