enbridgepartners.com
Enbridge Energy Partners, L.P.
Fourth Quarter 2014 Earnings & 2015 Financial Guidance Presentation
February 19, 2015
Enbridge Energy Partners, L.P. Fourth Quarter 2014 Earnings & - - PowerPoint PPT Presentation
Enbridge Energy Partners, L.P. Fourth Quarter 2014 Earnings & 2015 Financial Guidance Presentation February 19, 2015 enbridgepartners.com Legal Notice This presentation includes forward-looking statements and projections, which are
enbridgepartners.com
February 19, 2015
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This presentation includes forward-looking statements and projections, which are statements that do not relate strictly to historical
“believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “should,” “strategy,” “target”, “will” and similar words. Although Enbridge Energy Partners, L.P. (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; (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. Forward-looking statements regarding “drop-down” growth opportunities from Enbridge Inc. 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
Midcoast Energy Partners 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. 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
including its Annual Report on Form 10-K for the year ended December 31, 2014, 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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Solid Financial & Project Execution: Growth Outlook on-track
41% Total Unitholder Return 4.9% Distribution increases announced 2014 Financial guidance achieved First drop-down sale to MEP
Closed Equity Restructure with GP to enhance prospective cost of capital Completed $1 billion Drop-Down Acquisition ENB reviewing potential larger-scale US restructuring
~$2.3 billion of growth projects placed into service
Strong operational performance: record Liquids system deliveries ~ +20%
0.75 1.00 1.25 1.50
EEP AMZ 2014
Source: ThomsonOne
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Enbridge is the low cost transportation provider and we will continue to grow our pipeline systems
Heavy Crude Light Crude
February 10, 2015 pricing (Crude Prices: USD/bbl)
$47 $54 $56 $56 $47
*52 week period ended February 10, 2015.
Pacific Alberta Light WCS Bakken Light WTI Maya Brent
$50 $48 $45 $37
LLS
$45
Atlantic East Coast Heavy Differentials Peak* Current
WCS - Maya (16.35) (10.11) WCS – West Coast Heavy (29.32) (10.00) WCS - East Coast Heavy (14.35) (8.11) Alberta Light – WTI (15.53) (5.15) Alberta Light - Brent (18.71) (10.99) Bakken - LLS (14.00) (6.27) Bakken - ANS (15.95) (6.77)
$55
ANS
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Long-term investment horizon of Western Canadian producers
Sources: CAPP – Crude Oil Forecast, Markets and Pipelines (June 2014) with January 2015 updates, NEB, Enbridge
Actual Forecast
Jan 2015: CAPP updated production forecast kbpd WCSB Alternate Scenario
Near Term Oil Sands Projects in Service 2015 +370 kbpd 2016 +110 kbpd 2017 +175 kbpd
1,000 2,000 3,000 4,000 5,000 6,000 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
Near Term Oil Sands Projects in Service 2015 +370 kbpd 2016 +110 kbpd 2017 +175 kbpd
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Sources: Enbridge, North Dakota Pipeline Authority (January 9, 2015)
500 1,000 1,500 2,000 2,500 3,000 3,500
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024
kbpd
3rd Party Pipelines
Rail Transport Capacity
Enbridge 2014 Forecast NDPA Case 2 (Alternate Supply)
Enbridge Pipelines Local Refinery
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Pipelines provide the most economical transportation to market
Sources: CAPP, Genscape, Enbridge, North Dakota Pipeline Authority (January 9, 2015)
$16.30 to $22.60 All prices are USD/bbl $15.60 to $21.50 $15.30 to $22.45 $13.10 to $18.40 $8.65 to $16.05 $8.00 to $11.00 $12.00 to $13.00 $12.00 to $14.00
kbpd
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200 300 400 500 600 700 800 2015 2016 2017 2018 2019 2020 Alternate Senario Using CAPP Supply 100 200 300 400 500 600 700 800 2015 2016 2017 2018 2019 2020 Using NDPA Case 2
Forecast Rail Volumes
From Western Canada
Forecast Rail Volumes
From Bakken
kbpd kbpd
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still plenty of supply moving by rail from WSCB and Bakken
2015e EBITDA
EBITDA attributable to EEP (after deducting NCI) Cost of Service/Take-or-Pay. Fee-based: Commodity Sensitive:
Defensive nature of cash flows position EEP to navigate through commodity price uncertainty
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Organic Growth Projects:
Transformative low-risk organic growth expected to provide substantial cash flow growth
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
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New Build HP Upgrades
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 120 4 Line 3 at 760 370
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Initial Drop Down:
closed 1/2/2015
Alberta Clipper pipeline (Line 67)
Drop Down Outlook:
scale drop down plan to Partnership(1)
pipeline assets available
15% upsize options at cost
potential
Substantial drop down opportunities from ENB supports Partnership’s long-term growth outlook
Line 67
(1) On December 3, 2014, Enbridge Inc. announced it is reviewing a potential restructuring plan that would involve the transfer of its directly held U.S. liquids pipeline assets to Enbridge Energy Partners, L.P., a U.S. affiliate of Enbridge. This review is underway and has not progressed to a conclusion.
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Unaudited; adjusted results exclude the effect 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.
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 $22.5 million in 4Q 2014. 3 Distributable cash flow and Coverage metric excludes deferred distribution attributable to preferred unitholders. 4 Cash coverage excludes Paid-in-Kind distribution.
Financial Results Fourth Quarter 2014 Highlights
Strong Operational Performance + Project Execution = Solid Financial Performance
Deliveries
Deliveries
Replacement Phase II in-service
Coverage
Earnings
($millions, except per unit amounts)
4Q 2014 4Q 2013 FY 2014 FY 2013 Adjusted EBITDA1 $443.3 $303.3 $1,551.0 $1,143.4 Adjusted Net Income2 $132.5 $73.1 $460.3 $304.5 Adjusted Net Income per unit2 $0.27 $0.12 $0.93 $0.54 Cash Flow
($millions)
4Q 2014 4Q 2013 FY 2014 FY 2013 Distributable Cash Flow3 $214.4 $145.5 $809.3 $586.7 2014 2013 Coverage (as declared)3 0.90x 0.70x Cash Coverage (as declared)3,4 1.09x 0.82x
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Growing Financial Strength
Earnings & Cash Flow Outlook
500 1,000 1,500 2,000
2011 2012 2013 2014 2015e
$ millions
Liquids Projects Deliver EBITDA Growth
Based on adjusted EBITDA.
(1) Adjusted EBITDA on a fully consolidated basis; inclusive of non-controlling interest and other income. (2) North Dakota volume forecast does not include 100,000 bpd of take-or-pay volumes on Bakken Pipeline.
Enbridge Energy Partners
($ millions)
2014 2015e
Adjusted EBITDA(1) $1,551.0 $1,680 - 1,780 Distributable Cash Flow $809.3 $900 – 960 Coverage 0.90x 0.90 - 0.96x Cash Coverage 1.09x 1.10 - 1.20x 2014 2015e Lakehead 2,113 2,250– 2,450 North Dakota (2) 318 335 – 355 Mid-Continent 200 200 – 220 Total 2,631 2,785 – 3,025 2014 2015e Anadarko (Mmbtu/d) 827 825 – 900 East Texas (Mmbtu/d) 1,030 1,050 – 1,150 North Texas (Mmbtu/d) 293 300 – 330 Total (Mmbtu/d) 2,150 2,175 – 2,380 NGL Production (bpd) 83,675
88,000–92,000
Liquids Volumes (kbpd) Natural Gas & NGL Volumes
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Organic growth projects deliver low-risk, highly certain cash flow growth 2015 Project In-service Capital ($MM)1 Timing Line 67 Alberta Clipper +230 kbpd $240
2H 2015
Line 61 Southern Access + 240 kbpd Storage & Tankage $395 $360
2Q 2015 2Q15-2016
Line 78 + 570 kbpd $495
3Q 2015
Distribution coverage strengthens as growth projects enter service
Organic Growth Projects:
1 Represents 100% of forecasted capital cost. Eastern Access and US Mainline Expansion projects are jointly funded 75% by Enbridge
1 2 1 2 3 3
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2015 Adjusted EBITDA forecasted to increase ~ 12% over 2014
1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 1,800
Adjusted EBITDA1,2
($ MM) Eastern Access Eastern Access Mainline Exp Liquids Volume Growth Natural Gas Business
(1) Adjusted EBITDA on a fully consolidated basis; inclusive of non-controlling interest and other income. (2) Adjusted EBITDA assumes normalization of approximately $35MM of unrecovered costs associated with planned Lakehead Line 2 Hydro test.
1Q15e 2Q15e 3Q15e 4Q15e
Line 2 Hydrotest ($35MM)2 Preferred Units cash distribution payments ($45MM)
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2015 Capital Expenditures & Investments ($ millions)
1 Eastern Access and US Mainline Expansion capital expenditures are forecasted net of joint funding, with assumed Enbridge Inc. 75% funding; Line 3 joint funding currently being
negotiated with Enbridge Inc.. Assumes 50-50 joint 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 current base 48.4% funding by EEP and 51.6% by MEP.
3On January 29, 2015, the board of directors of Enbridge Management constituted a committee of independent directors to evaluate a potential new 364-day credit agreement with
Enbridge for up to $750 million.
Eastern Access1 100 US Mainline Expansions1 270 Sandpiper1 305 Line 3 Replacement1 30 Liquids Integrity 225 Liquids Other Growth Enhancements 155 Natural Gas Growth Projects2 140 Maintenance Capital Expenditures2 100 Total Capital Expenditures $1,325 Alberta Clipper Investment $1,000
Maintaining Strong Investment Grade Credit Rating is a Top Priority (BBB+/Baa2)
523 198 7503
500 1,000 1,500 12/31/2014 $ millions
Credit Facilities Cash
$1,471
Available Liquidity
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price environment
(1) On December 3, 2014, Enbridge Inc. announced it is reviewing a potential restructuring plan that would involve the transfer of its directly held U.S. liquids pipeline assets to Enbridge Energy Partners, L.P., a U.S. affiliate of Enbridge. This review is underway and has not progressed to a conclusion.
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Defensive nature of cash flows position EEP to navigate through commodity price uncertainty
Unconsolidated View
32% 27% 18%
Crude oil projects progressively transform EEP to much 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 commodities length; 2015 contribution is after-hedging. Assumes natural gas business as held by Midcoast Operating, L.P. is dropped down to MEP by the end of 2017. Contribution is based on revenues from Liquids segment and gross margin from Natural Gas segment, excluding non-controlling interest.
2018e 2015e
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Distributable Cash
Pipeline System Upsize Option Capital Cost/ Book Value*
$0.4 (2016/2017) ~ $1.5
$0.4 (2016/2017) ~ $1.4
$0.4 (2018) ~ $0.9
Extension
* Estimated capital cost or net book value of assets held by Enbridge Inc. ** 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. Capital cost assumes 50% estimated funding by Enbridge Inc..
Examples:
Potential: $10 Billion +
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Adjusted Operating Income Volumes
Unaudited; adjusted results exclude the effect 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.
185.8 205.2 232.8 269.7 306.4
50 100 150 200 250 300 4Q13 1Q14 2Q14 3Q14 4Q14 $ millions
1.92 2.00 2.09 2.17 2.19 0.20 0.21 0.18 0.19 0.22 0.20 0.25 0.31 0.35 0.36
1.00 1.50 2.00 2.50 3.00
4Q13 1Q14 2Q14 3Q14 4Q14
Volume by System (mmbpd)
Lakehead Mid-Continent North Dakota
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Unaudited; adjusted results exclude the effect 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
902 824 819 806 858 1,028 971 1,029 1,063 1,056 292 272 300 304 297
1,000 1,500 2,000 2,500 3,000 4Q13 1Q14 2Q14 3Q14 4Q14
Volume by System (mmbtu/d in thousands)
Anadarko East Texas North Texas
NGL Production attributable to lost customer
($millions) 4Q 2014 FY 2014 Adjusted Operating Income $5.1 $15.2
and NGL volume growth
Marketing as expected
gas developments
40,000 60,000 80,000 100,000 4Q13 1Q14 2Q14 3Q14 4Q14 NGL Production (bpd)