First Quarter 2013 Earnings Presentation May 1, 2013 Slides posted - - PowerPoint PPT Presentation

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First Quarter 2013 Earnings Presentation May 1, 2013 Slides posted - - PowerPoint PPT Presentation

First Quarter 2013 Earnings Presentation May 1, 2013 Slides posted at www.enbridgepartners.com/q Legal Notice This presentation includes certain forward looking information (FLI) to provide Enbridge Energy Partners, L.P. (EEP) and


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SLIDE 1

First Quarter 2013 Earnings Presentation

May 1, 2013

Slides posted at www.enbridgepartners.com/q

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SLIDE 2

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 Enbridge Partners’ 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) Enbridge Partners’ 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 Enbridge Partners or refineries, petrochemical plants, utilities or other businesses for which Enbridge Partners transports products or to whom Enbridge Partners sells products; (5) hazards and operating risks that may not be covered fully by insurance; (6) changes in or challenges to Enbridge Partners’ tariff rates; and (7) changes in laws or regulations to which Enbridge Partners is subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance. Our FLI is 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. 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

  • therwise. All FLI in this presentation is expressly qualified in its entirety by these cautionary statements. You are referred to

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, for a more detailed discussion of risk factors. This presentation makes reference to certain financial measures, such as adjusted net income, which are not recognized under generally accepted accounting principles, referred to as GAAP.

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SLIDE 3

Agenda

3

1. Project Update 2. Market Access Program 3. Financial Highlights 4. Question & Answer

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SLIDE 4

Project Update

4

Liquids Bakken Pipeline Expansion Bakken Berthold Rail Bakken Access Line 6B 75-mile replacement Eastern Access (Line 5 exp. ) Mainline Expansions Sandpiper Natural Gas Ajax gas plant Texas Express NGL Pipeline

U/C

U/C U/C U/C

In-service Under construction Being phased-in Regulatory process

U/C

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SLIDE 5

G&P Growth Update – Expand ETX Processing Capacity

5

Project Overview

  • Construction of 150 MMcf/d cryogenic natural gas processing plant – Beckville Plant (Panola county)
  • Will expand EEP’s processing capacity in ETX Cotton Valley/Haynesville region to 820 MMcf/d
  • Capital investment ~$140 million; attractive EBITDA multiple; in-service early 2015
  • Cotton Valley: covers 10 counties in ETX; region currently produces ~ 1.8 Bcf/d of natural gas,

with 72 kbpd of associated NGLs ~2.5-3.0 GPM gas

Expand G&P Strategic Asset Footprint

Consistent with EEP strategy to optimize existing infrastructure

Competitive advantage due to extensive gathering footprint

Incremental NGL volumes will enhance EEP’s downstream integration strategy

Increases East Texas volume diversification

Generates incremental distributable cash flow ~ accretive growth

Potential for additional investment opportunities

Commercial Underpinnings

  • Combination of fee + commodity based contracts with acreage dedication
  • Active large-scale producers in the region
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SLIDE 6

Linking North American Crude Supply Growth to Refining Centers

Cushing Houston Chicago/ Flanagan Port Arthur 1 3 2 Enbridge Energy Partners Projects (EEP) ~ $7.3B*

Sandpiper Pipeline Project ($2.5B)

  • +225/375 kbpd early 2016

US Mainline Expansions ($2.4B): Line 67 Expansion (border to Superior)

  • +350 kbpd, total 800 kbpd; 3Q14 to 2015

Line 61 Expansion (Superior to Flanagan)

  • +800 kbpd, total 1,200 kbpd; 3Q14 to 2016

Chicago Connectivity

  • +570 kbpd Line 62 twin mid-2015

Eastern Access Expansions ($2.4B): Line 5 Expansion

  • +50 kbpd 2Q13

Line 62 Spearhead North Expansion

  • +105 kbpd 4Q13

Line 6B Replacement

  • +260 kbpd late 2013/early 2014; +70 kbpd early 2016
  • Eastern Access & US Mainline Expansions

EEP/ENB joint funded

*represents total capital before joint funding

3 1 2 3

6

Montreal Superior

Canadian/U.S. East Coast Refinery Markets U.S. Gulf Coast Refinery Markets

Sarnia EEP North Dakota System Patoka Enbridge (ENB) & Enbridge Partners (EEP) Market Access Programs

  • U.S. Gulf Coast Access
  • Eastern Access
  • Light Oil Market Access

4 5 4 5 6 5 1 2 4 6 6

U.S. Mid-West Refinery Markets

Enbridge Inc. Projects (ENB)

Seaway Pipeline - ENB and EPD JV

  • +400 kbpd 1Q13

Flanagan South Pipeline

  • +585 kbpd (36” line) mid-2014

Seaway Pipeline Twin & Lateral

  • ENB and EPD JV; +450k bpd 1H 2014

Toledo Pipeline Partial Twin

  • +80 kbpd 2013

Line 9 Reversal & Expansion

  • +240 kbpd late 2013, 2014;+80 kbpd 2014

Southern Access Extension

  • +300 kbpd 2015

Trunkline JV

  • +440 to 660 kbpd 2015

1

Growth Projects:

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

5 2 3 4 5 6 7 Memphis

  • St. James

7

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SLIDE 7

Delivering Low-Risk Sustainable Growth

7

Note: Eastern Access and Mainline Expansion liquids expansion projects are jointly funded by EEP & ENB.

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 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 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 Ajax Plant Texas Express NGL Pipeline JV

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SLIDE 8

Business Mix & Risk Profile

*Note: based on 2013 forecast

Liquids Pipelines 80% Natural Gas 20%

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.

8

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SLIDE 9

Financial Highlights

1Q 109.2 1Q 95.7

50 100

2012 2013

$ millions

Excludes earnings attributable to non-controlling interest

Adjusted Net Income Adjusted EBITDA Adjusted Earnings Per Unit As-declared Coverage Ratio

1Q 291.5 1Q 281.0

50 100 150 200 250 300

2012 2013

$ millions

Includes non-controlling interest

1Q $0.28 1Q $0.21

$0.00 $0.10 $0.20 $0.30

2012 2013

Excludes earnings attributable to non-controlling interest

YTD 0.79x YTD 0.79x

0.00x 0.20x 0.40x 0.60x 0.80x 1.00x

2012 2013

Unaudited; adjusted results exclude the impact 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.

9

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SLIDE 10

Liquids Segment Results

10

1.86 1.81 1.76 1.74 1.84 0.24 0.24 0.21 0.21 0.22 0.22 0.22 0.21 0.17 0.13

  • 0.50

1.00 1.50 2.00 2.50

1Q12 2Q12 3Q12 4Q12 1Q13

Volume by System (mmbpd)

Lakehead Mid-Continent North Dakota

159.0 155.5 153.5 133.0 154.3

50 100 150 200 1Q12 2Q12 3Q12 4Q12 1Q13 $ millions

Adjusted Operating Income Volumes

Unaudited; adjusted results exclude the impact 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.

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SLIDE 11

Natural Gas Segment

11

Adjusted Operating Income Volumes / Rig Count

52.5 43.3 60.2 42.9 26.4

10 20 30 40 50 60 70 1Q12 2Q12 3Q12 4Q12 1Q13 $ millions

942 1,062 1,065 998 964 1,319 1,291 1,219 1,233 1,252 315 332 343 333 332

  • 100

200 300 400 500 600 700 800

  • 500

1,000 1,500 2,000 2,500 3,000 1Q12 2Q12 3Q12 4Q12 1Q13 Average Rig Count EEP Main Regions Volume by System (mmbtu/d in thousands) Anadarko East Texas North Texas Rig Count

Unaudited; adjusted results exclude the impact 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.

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SLIDE 12

Forecasted Capital Expenditures

2013 Capital Expenditures Forecast Available Liquidity

1 Eastern Access and US Mainline Expansion capital expenditures are forecasted net of joint funding, with assumed Enbridge Inc. 60% funding; all amounts in $ millions.

Core Maintenance $130 Eastern Access1 490 US Mainline Expansions1 130 North Dakota Expansion & Rail 185 Line 6B 75-mile Replacement 95 Liquids Integrity 275 Cushing Storage 45 Liquids Other Growth Enhancements 290 Ajax Gas Processing Plant 55 Texas Express NGL Pipeline 185 NG Other Growth Enhancements 275 Total $2,155

12

1,283 1,611 228 242

500 1,000 1,500 2,000 12/31/2012 3/31/2013 $ millions

Credit Facilities Cash

1,852 1,511

Strong investment grade credit profile (BBB/Baa2)

  • Executed on ~$273 million public
  • ffering of EEQ shares in 1Q13
  • Joint Funding with Enbridge

enhances financing flexibility

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SLIDE 13

13

Strengthening Distribution Coverage

Secured growth projects improve distribution coverage

0.00x 0.25x 0.50x 0.75x 1.00x 1.25x 2006 2007 2008 2009 2010 2011 2012 2013(e) 2016(e) Long Range Coverage Target

Guidance range

Transition to high end of distribution growth target Coverage*

* Coverage includes EEQ paid-in-kind distribution.

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SLIDE 14

Key Takeaways

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  • Operational excellence, system integrity, safety and project

execution are top priorities

  • Growth projects entered service in first quarter

– Distributable cash flow growth will continue to ramp-up and coverage

strengthens as organic growth projects enter service

  • Secured Liquids growth projects collectively further transform the

Partnership to lower risk business model

  • Strong liquidity position secured to support organic growth platform
  • Maintaining investment grade credit rating is a priority
  • Distribution growth: targeting 2% to 5% annual growth
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SLIDE 15