Supplemental Slides Enbridge Energy Partners, L.P. Fourth Quarter - - PowerPoint PPT Presentation

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Supplemental Slides Enbridge Energy Partners, L.P. Fourth Quarter - - PowerPoint PPT Presentation

Supplemental Slides Enbridge Energy Partners, L.P. Fourth Quarter 2014 Earnings & 2015 Financial Guidance Presentation February 19, 2015 Legal Notice This presentation includes forward-looking statements and projections, which are


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Supplemental Slides

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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Quarter Earnings

(Adjusted)* $ 306.4 $ 185.8 $ 120.6 5.1 4.4 0.7 (3.7) (2.2) (1.5) 307.8 188.0 119.8 7.0 (2.1) 9.1 9.4 17.9 (8.5) (82.2) (73.1) (9.1) (3.5) (1.2) (2.3) (83.5) (34.0) (49.5) (22.5) (22.4) (0.1) 132.5 73.1 59.4 (43.6) (33.9) (9.7) $ 88.9 $ 39.2 $ 49.7 329.8 325.2 4.6 $ 0.27 $ 0.12 $ 0.15 $ 443.3 $ 303.3 $ 140.0 * Interest expense Quarter Ended December 31, 2014 2013 Change Segmented operating income (loss):

  • Liquids
  • Natural Gas
  • Corporate

Operating income Allowance for equity used during construction Other income

Excludes the impact of: (a) unrealized noncash mark-to-market net gains and losses; and (b) additional environmental costs, net of insurance recoveries, associated w ith the incident on Line 6B; among other adjustments – see non-GAAP reconciliations.

Income tax expense Less: Net income attributable to: Series 1 preferred unit distributions Net income attributable to general and limited partner ownership in EEP Allocations to general partner Net income allocable to common units and i-units Noncontrolling interest Weighted average common units and i-units outstanding Net income per common unit and i-unit Adjusted EBITDA

(Unaudited; $ in millions, except per unit in dollars; average units in millions)

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Distribution Coverage

Net income attributable to general and limited partner ownership in EEP $ 214.1 $ 214.1 $ 371.8 $ 371.8 Option premium amortization (0.9) (0.9) (4.1) (4.1) Noncash derivatives fair value gains (99.6) (99.6) (33.8) (33.8) Make-up rights adjustment (2.0) (2.0) 6.5 6.5 Line 6B incident expense, net of recoveries 1.0 1.0 88.9 88.9 Non-core asset impairment 11.9 11.9 11.9 11.9 Severance costs 4.2 4.2 4.2 4.2 Accretion of discount on Series 1 preferred units 3.8 3.8 14.9 14.9 Adjusted net income 132.5 132.5 460.3 460.3 Series 1 preferred unit distributions 22.5 22.5 90.0 90.0 Depreciation and amortization 91.3 91.3 365.0 365.0 Distribution in excess of income from Joint Ventures (0.1) (0.1) 2.7 2.7 Maintenance Capex (31.8) (31.8) (108.7) (108.7) Distributable Cash Flow $ 214.4 $ 214.4 $ 809.3 $ 809.3 Cash Distributions 194.2 183.7 743.6 727.8 PIK Distributions (gross)* 39.7 38.1 151.3 146.9 Total Distributions $ 233.9 $ 221.8 $ 894.9 $ 874.7 Cash Coverage Ratio 1.10 1.17 1.09 1.11 Coverage Ratio 0.92 0.97 0.90 0.93 Distribution per unit $ 0.5700 $ 0.5550 $ 2.2235 $ 2.1970 (Unaudited; $ in millions) * Notional value of paid in kind distributions. As declared As paid As declared As paid Q4 2014 Q4 2014 YTD 2014 YTD 2014

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Segment Operating Income

(Adjusted)*

* Excludes the impact of: (a) unrealized noncash mark-to-market net gains and losses; and (b) additional environmental costs, net of insurance recoveries, associated with the incident on Line 6B; among other adjustments - see non-GAAP reconciliations. Liquids $ 603.8 $ 420.1 $ 183.7 (62.6) (41.9) (20.7) (3.0) (2.3) (0.7) (147.7) (126.2) (21.5) (84.1) (63.9) (20.2) Adjusted Operating income $ 306.4 $ 185.8 $ 120.6 Quarter Ended December 31, (Quarterly information is unaudited; $ in millions) Depreciation and amortization Operating revenue Power Environmental costs Operating and administrative Change 2013 2014 Natural Gas Gross Margin $ 143.9 $ 151.6 $ (7.7) Operating and administrative (100.7) (110.7) 10.0 Depreciation and amortization (38.1) (36.5) (1.6) Adjusted Operating income $ 5.1 $ 4.4 $ 0.7 Quarter Ended December 31, 2013 2014 Change (Unaudited; $ in millions)

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Impact of Line 6B Incident

As of September 30, 2014 Booked in Q4 2014 Total to Date Total Costs $1,208 $1 $1,209 Less: Insurance Recoveries $547 $0 $547 Total Normalized $661 $1 $662 Estimated Costs*

*Includes $47.5 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, $ in millions. Represents life-to-date amounts pursuant to impact of the Line 6B incident.

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Capital Expenditures

Maintenance Capex $ 38.8 $ 129.8 Enhancement Capex (1)(2) $ 737.7 $ 2,669.6 Ending PP&E, net $ 15,692.7 North Dakota Expansions (1) $ 219.0 $ 366.4 Eastern Access (2) $ 73.9 $ 706.8 Mainline Expansion (2) $ 256.4 $ 712.6

(1) Enhancement expenditure is before joint funding, with 37.5% to be funded by third party (2) Enhancement expenditure is before Eastern Access and Mainline Expansion joint funding, with 75%

to be funded by Enbridge Inc. Q4 2014 FY 2014 Q4 2014 Major Enhancement Expenditures Q4 2014 FY 2014 (Unaudited; $ in millions)

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Book Capitalization

12/31/2014 12/31/2013 Loans from affiliates $ 306.0 $ 318.0 Short-term debt

  • 200.0

Long-term debt(1) 6,475.2 4,577.4 Total Debt $ 6,781.2 $ 5,095.4 Partners' capital(1) 9,140.8 7,974.0 Total Capitalization $ 15,922.0 $ 13,069.4 Total Debt / Total Capitalization 43% 39% 12/31/2014 12/31/2013 Amounts outstanding under Credit Facilities $ 1,210.0 $ 335.0 Principal amount of Commercial Paper issuances 562.3 300.0 Letters of Credit outstanding 330.2 76.7 Amount we could borrow 522.5 2,463.3 Total credit available under Credit Facilities (2) $ 2,625.0 $ 3,175.0 (Unaudited; $ in millions)

(1) (2)

Debt reduced and Partners' Capital increased in 2014 and 2013 by $200 million for Junior Subordinated Notes' equity credit. Partners' Capital excludes Accumulated Other Comprehensive Income and includes Noncontrolling Interest. EEP's available liquidity excludes credit available to its affiliates MEP and MOLP under their respective credit agreement.

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Volume History

Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 2012 2013 2013 2013 2013 2014 2014 2014 2014 Liquids Business - Volumes (kbpd) Lakehead 1,737 1,836 1,683 1,825 1,918 2,000 2,088 2,172 2,187 Mid-Continent 207 222 170 216 195 211 176 191 222 North Dakota 173 128 151 206 200 245 314 347 362 Total 2,117 2,186 2,004 2,247 2,313 2,456 2,578 2,710 2,771 East Texas 1,233 1,252 1,211 1,120 1,028 971 1,029 1,063 1,056 Anadarko 998 964 972 957 902 824 819 806 858 North Texas 333 332 333 314 292 272 300 304 297 Total 2,564 2,548 2,516 2,391 2,222 2,067 2,148 2,173 2,211 East Texas 314 310 321 306 315 305 330 322 318 Anadarko 763 768 774 799 700 636 637 664 793 North Texas 266 253 263 248 235 236 253 251 245 Total 1,343 1,331 1,358 1,353 1,250 1,177 1,220 1,237 1,356 NGL Production -Volumes (bpd) Total 101,533 88,498 91,245 88,952 84,288 80,899 83,480 84,121 86,136 Natural Gas Business - Volumes ('000 MMbtu/d) Natural Gas Processing - Volumes ('000 mcf/d)

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Key 2015 Guidance Assumptions

Liquids Volumes (kbpd) 2014 2015e Lakehead System 2,113 2,250 – 2,450 North Dakota System* 318 335 – 355 Mid-Continent System 200 200 – 220 Total 2,631 2,785 – 3,025 Natural Gas Volumes (‘000 MMbtu/d) 2014 2015e East Texas 1,030,000 1,050 – 1,150 Anadarko 827,000 825 - 900 North Texas 293,000 300 – 330 Total 2,150,000 2,175 – 2,380 NGL Production (Bpd) 2014 2015e Total 83,675 88,000 – 92,000 2015e Operating Expenses ($millions) Liquids: Power costs $290 - $310 EEP Operating and Admin. Expenses $1,050 - $1,100

* North Dakota System volumes do not include 100,000 bpd of take-or- pay volumes on Bakken Pipeline.

Lakehead ($millions) Description 2015e Revenue Index $ +/- 685 Southern Access $ +/- 310 Alberta Clipper $ +/- 210 Eastern Access $ +/- 340 Mainline Expansion $ +/- 125 Facilities Surcharge $ +/- 265 Allowance Oil $ +/- 30 Total Transportation Revenues $ +/- 1,970 North Dakota and Bakken Expansion ($millions) Description 2015e Revenue Total Transportation Revenues $ +/- 320 Mid-Continent ($millions) Description 2015e Revenue Total Revenues $ +/- 145

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Estimated Commodity Positions

(1) Represents Estimated Commodity Positions for the Gathering, Processing and Transportation Segment of Midcoast Operating, L.P. for January – December 2015. Unaudited, $ in millions. (2) Options valued at their strike prices to determine hedged cash flows. (3) Commodity sensitivity of unhedged commodity positions for the Gathering Processing & Transportation segment at Midcoast Operating as of 1/16/2015.

Hedge Weighted Avg Hedged Cash Flows (2) % Hedge Price $ MM Natural Gas (9,714) MMbtu/d 0% MMbtu/d $0.00 /MMbtu ($0.1) C2 6,918 bpd bpd $0.00 /gallon $0.0 C3 6,525 bpd 80% 5,250 bpd $0.93 /gallon $75.1 iC4 1,387 bpd 54% 750 bpd $1.06 /gallon $12.2 C4 2,275 bpd 59% 1,349 bpd $1.04 /gallon $21.5 C5 1,101 bpd 95% 1,050 bpd $1.90 /gallon $30.6 Total NGLs 18,206 bpd 46% 8,399 bpd $139.4 Condensate 4,019 bpd 72% 2,910 bpd $85.12/barrel $90.4 2015 Hedged Commodity Gross Margin $229.7 Equity Length Volume

2015 Estimated Commodity Positions (1)

Physical Hedged

(15) (10) (5)

  • 5

10 15 2015 2016

Commodity Price Sensitivity (3)

Prices: -10% Prices: +10%

$ (January – December 2015)

2015 Weighted Avg 2016 Weighted Avg Hedge Price Hedge Price Natural Gas $0.00 /MMbtu $0.00 /MMbtu C2 $0.00 /gallon $0.00 /gallon C3 $0.93 /gallon $0.85 /gallon iC4 $1.06 /gallon $0.93 /gallon C4 $1.04 /gallon $1.04 /gallon C5 $1.90 /gallon $1.41 /gallon Condensate $85.12/barrel $75.91/barrel

> 80% Hedged (4) > 65% Hedged (4)

(4) Portfolio hedge percentage based on commodity positions and forward prices as of 1/29/2015.

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GAAP Reconciliation

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Fourth Quarter Earnings (GAAP)

$ 321.6 $ 97.8 $ 223.8 132.8 9.8 123.0 (3.7) (2.2) (1.5) 450.7 105.4 345.3 6.7 15.0 (8.3) 9.4 17.9 (8.5) 109.0 94.0 15.0 3.5 1.2 2.3 354.3 43.1 311.2 113.9 34.0 79.9 22.5 22.4 0.1 3.8 3.5 0.3 214.1 (16.8) 230.9 $ 168.9 $ (48.9) $ 217.8 329.8 325.2 4.6 $ 0.51 $ (0.15) $ 0.66 329.8 325.2 4.6 $ 0.51 $ (0.15) $ 0.66 Noncontrolling Interest Net income (loss) attributable to general and limited partner ownership in EEP Net income (loss) allocable to common units and i-units Net income (loss) per common unit and i-unit (diluted) Series 1 preferred unit distributions Accretion of discount on Series 1 preferred units Weighted average common units and i-units outstanding (basic) Net income (loss) per common unit and i-unit (basic) Weighted average common units and i-units outstanding (diluted)

(Unaudited; $ in millions, except per unit in dollars; average units in millions).

Quarter Ended December 31, Income tax expense 2014 2013 Change Segmented and corporate operating income (loss):

  • Liquids
  • Natural Gas
  • Corporate

Other income Operating income Interest expense Allowance for equity used during construction Net income Less: Net income attributable to:

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Adjusted Earnings

$ 214.1 $ (16.8) $ 371.8 $ 4.7

  • Liquids

(14.5) (0.4) (13.5) 3.9

  • Natural Gas

(111.9) (8.1) (120.4) 3.6

  • Corporate

26.8 20.9 100.1 21.7 Non-core asset impairment 11.9

  • 11.9
  • Severance costs

4.2

  • 4.2
  • (0.9)

2.7 (4.1) 4.7 (2.0) 1.3 6.5 1.6

  • 12.1

1.0 87.1 88.9 260.1

  • (17.1)
  • (17.1)

3.8 3.5 14.9 9.2 132.5 73.1 460.3 304.5 43.6 33.9 155.2 133.4 $ 88.9 $ 39.2 $ 305.1 $ 171.1 329.8 325.2 328.2 316.2 $ 0.27 $ 0.12 $ 0.93 $ 0.54 (Unaudited; $ in millions, except per unit in dollars, average units in millions) Q4 2014 Q4 2013 FY 2014 FY 2013 Net income (loss) attributable to general and limited partner

  • wnership interest in Enbridge Energy Partners, L.P.

Adjusted net income allocable to common units and i-units Weighted average common units and i-units (millions) Adjusted net income per common unit and i-unit (dollars) Noncash derivative fair value (gains) losses Option premiums Make-up rights adjustment Accretion of discount on Series 1 preferred units Adjusted net income Less: Allocations to General Partner Deferred tax law adjustment Line 6B incident expenses, net of recoveries Sale of El Dorado tank farm

  • The foregoing presentation makes reference to adjusted net income in order

to exclude the effect of non-cash derivative fair value gains and losses and

  • ther non-recurring items. A reconciliation to net income per GAAP is

provided below.

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Adjusted Segment Operating Income

  • The foregoing presentation makes reference to adjusted operating income

(loss), which combines certain GAAP measures as shown below.

$ 321.6 $ 97.8 $ 132.8 $ 9.8 1.0 87.1

  • (14.5)

(0.4) (146.9) (8.1) Option premium amortization (gains) losses

  • (1.2)

2.7 Make-up rights adjustment (2.3) 1.3

  • Non-core asset impairment
  • 15.6
  • Severance costs

0.6

  • 4.8
  • $

306.4 $ 185.8 $ 5.1 $ 4.4

(Unaudited; $ in millions)

Adjusted operating income Natural Gas Q4 2014 Q4 2013 Q4 2014 Q4 2013 Operating income Line 6B incident expenses, net of recoveries Noncash derivative fair value (gains) losses Liquids

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Adjusted Gross Margin

  • The foregoing presentation makes reference to gross margin for the Natural

Gas segment, which combines certain GAAP measures as shown below.

$ 1,451.2 $ 1,120.3 (1,159.2) (962.8) (146.9) (9.0) Option premium amortization (1.2) 2.7 $ 143.9 $ 151.2

(Unaudited; $ in millions)

Adjusted gross margin Natural Gas Q4 2014 Q4 2013 Operating revenues Commodity costs Noncash derivative fair value gains

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Adjusted EBITDA

  • The foregoing presentation makes reference to adjusted EBITDA which is used as a

supplemental financial measurement to assess liquidity and the ability to generate cash sufficient to pay interest costs and make cash distributions to unitholders. A reconciliation of net cash provided by operating activities to adjusted EBITDA is provided below.

FY 2014 FY 2013 $ 325.1 $ 269.9 $ 816.8 $ 1,212.4 net of cash acquired 30.3 (65.1) 379.8 (357.2) 82.2 73.1 303.1 298.7 3.5 1.2 9.6 18.7 9.4 17.9 57.2 43.1

  • (17.1)
  • (17.1)

(1.2) 2.4 (5.2) 4.4

  • (12.1)
  • (42.0)

(6.0) 21.0 (10.3) (5.5) $ 443.3 $ 303.3 $ 1,551.0 $ 1,143.4

(1)

El Dorado tank farm sale

Net cash provided by operating activities Changes in operating assets and liabilities, Q4 2014 Q4 2013 Interest expense excludes unrealized mark-to-market net losses of $26.8 million and $100.1 million for the three and twelve month periods ended December 31, 2014, respectively. Interest expense excludes unrealized mark-to- market net gains of and $20.9 million and $21.7 million for the three and twelve month periods ended December 31, 2013, respectively. (Unaudited; $ in millions) Interest expense (1) Income tax expense Adjusted EBITDA Other

Allowance for equity used during construction Option premium amortization Deferred tax law adjustment Line 6B insurance recoveries received