Enbridge Energy Partners, L.P. Fourth Quarter 2014 Earnings & - - PowerPoint PPT Presentation

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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


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enbridgepartners.com

Enbridge Energy Partners, L.P.

Fourth Quarter 2014 Earnings & 2015 Financial Guidance Presentation

February 19, 2015

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Legal Notice

This presentation includes forward-looking statements and projections, which are statements that do not relate strictly to historical

  • r current facts. These statements frequently use the following words, variations thereon or comparable terminology: “anticipate,”

“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

  • interests. Similarly, any forward-looking statements regarding potential “drop-down” transactions of interests in Midcoast Operating to

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

  • therwise. 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, 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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Agenda

  • 1. 2014 Highlights
  • 2. Crude Oil Price

Environment Implications

  • 3. Liquids Pipelines Growth
  • 4. Drop down Outlook
  • 5. 4Q Financial Results
  • 6. 2015 Financial Guidance
  • 7. Question & Answer
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2014 Highlights

Solid Financial & Project Execution: Growth Outlook on-track

Financial Execution

41% Total Unitholder Return 4.9% Distribution increases announced 2014 Financial guidance achieved First drop-down sale to MEP

Growth Outlook

Closed Equity Restructure with GP to enhance prospective cost of capital Completed $1 billion Drop-Down Acquisition ENB reviewing potential larger-scale US restructuring

Project Execution

~$2.3 billion of growth projects placed into service

Continued Focus on Safety & Operational Reliability

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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North American Crude Oil Pricing Differentials

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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WCSB Crude Oil Fundamentals and Outlook

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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Bakken Crude Supply Forecast vs Take Away Capacity

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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Rail Perspective

Pipelines provide the most economical transportation to market

Sources: CAPP, Genscape, Enbridge, North Dakota Pipeline Authority (January 9, 2015)

Rail Transportation Costs

$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

7

Western Canada Bakken

  • 100

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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Strong Commercial & Fundamental Underpinnings

Low-risk business model largely mitigates

volume sensitivity

Demand for crude oil and pipeline capacity

from Western Canada and Bakken remains strong

Customer demand & connectivity Enbridge/Partnership’s system is currently

  • versubscribed

Pipelines provide the most economical

transportation to market

still plenty of supply moving by rail from WSCB and Bakken

Liquids pipeline system volume outlook remains strong despite low crude oil prices

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:

 Commercially secured  Low risk framework  Long-term contracts

Market Access Well Advanced

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

Three major initiatives provide 1.7 MMbpd

  • f increased market access and diversification
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Low Cost Expansion & Extension Opportunities

New Build HP Upgrades

Low cost phased expansions are attractive in a low crude price environment

NTD: Map to be updated

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 120 4 Line 3 at 760 370

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Initial Drop Down:

  • $1 billion drop down from Enbridge

closed 1/2/2015

  • 66.7% interest in the U.S. segment of

Alberta Clipper pipeline (Line 67)

  • Immediately accretive
  • 2.7% distribution increase announced
  • No public equity required by EEP

Drop Down Outlook:

  • Enbridge reviewing potential larger

scale drop down plan to Partnership(1)

  • Over $10 billion of U.S. liquids

pipeline assets available

  • Eastern Access & Mainline Expansion

15% upsize options at cost

  • Enhances EEP’s distribution growth

potential

Drop Downs Boost Distributable Cash Flow

Substantial drop down opportunities from ENB supports Partnership’s long-term growth outlook

Enbridge reviewing potential larger scale drop-down plan to EEP (1)

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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2014 Financial Summary

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

 Record Lakehead System

Deliveries

 Record North Dakota System

Deliveries

 Eastern Access Line 6B

Replacement Phase II in-service

 Strengthening Distribution

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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Financial Outlook 2015

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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Market Access Growth Projects On-Track

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:

 Commercially secured  Low risk framework  Long-term contracts

1 Represents 100% of forecasted capital cost. Eastern Access and US Mainline Expansion projects are jointly funded 75% by Enbridge

  • Inc. and 25% by EEP.

1 2 1 2 3 3

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Low Risk Earnings and Cash Flow Growth

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

 Eastern Access & Mainline Expansions full-year project contributions  Line 61 to 800kbpd (ME)  Beckville plant  Line 78 in-service (ME)  Line 67 to 800kbpd (ME)

 Line 2 Hydrotest ($35MM)2  Preferred Units cash distribution payments ($45MM)

2015 Earnings and Cash Flow Outlook

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Forecasted Capital Expenditures and Available Liquidity

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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Key Takeaways

Low-risk business model

  • Well positioned in current uncertain commodity price environment

Transformative growth underway

  • Organic growth on-track: coverage continues to strengthen as projects enter service

Low cost organic growth potential

  • Low cost ‘bolt-on’ expansion and extension opportunities remain plentiful in low crude

price environment

Strategic alignment with Enbridge supports long-term growth outlook

  • Enbridge reviewing potential larger scale drop down plan to EEP

Safety and operational reliability are cornerstones that underpin

  • ur business and growth outlook

(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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Appendix

Enbridge Energy Partners, L.P.

Fourth Quarter 2014 Earnings & 2015 Financial Guidance Presentation

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Risk Profile – Low Risk Business Model

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*

  • Eastern Access

$0.4 (2016/2017) ~ $1.5

  • Mainline Expansion

$0.4 (2016/2017) ~ $1.4

  • Line 3 Replacement**

$0.4 (2018) ~ $0.9

  • Southern Access

Extension

  • ~ $0.6
  • 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 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..

~ $10B +

Examples:

Enbridge Liquids Pipelines Drop-Down

Potential: $10 Billion +

        

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Liquids Segment

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

  • 0.50

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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Natural Gas Segment

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

  • 500

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

Operational Highlights

  • Four sequential quarters of natural gas

and NGL volume growth

  • Strong seasonal results in Logistics &

Marketing as expected

  • NGL production benefitting from richer

gas developments

40,000 60,000 80,000 100,000 4Q13 1Q14 2Q14 3Q14 4Q14 NGL Production (bpd)