second quarter 2016 earnings presentation - enbridge/media/eepeeqmep/events/eepeeq/20… · q2 2016...
TRANSCRIPT
Second Quarter 2016
Earnings Presentation
July 28, 2016
Enbridge Energy Partners, L.P.
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) costs in connection with complying with the settlement consent decree related to Line 6B and Line 6A, which is still subject to court approval, and/or the failure to receive court approval of, or material modifications to, such decree; (7) changes in or challenges to the Partnership’s tariff rates; (8) 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 (9) 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.
Agenda
SLIDE 3
1. Line 6B Update
2. Crude Oil Fundamentals
3. Financial Summary
4. Low-risk Business Model
5. Question & Answer
Safety and Operational Reliability
• Primary components to terms of settlement with U.S. DOJ and U.S. EPA
• Civil penalties under Clean Water Act for 2010 incidents on Line 6B ($61 million) and Line 6A ($1 million)
• Safety measures cost estimated at $110 million over four-year term of the decree and is largely incorporated in operational and capital expense planning
• Pipeline replacement
• Replaced Line 6B in 2014
• Replacement of Line 3, underway
• Focused first and foremost on the safety and operational reliability of our systems
• Fulfilled commitment to thoroughly clean up and restore area and to cover the costs
SLIDE 4
Line 6B Settlement
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 5
Early 2019 in-service; reduced near-term capital requirements
Line 3
Sandpiper
Western Canadian Supply Growth Outlook
Source: CAPP Crude Oil Forecast, Markets and Transportation (June 2016 CAPP Forecast)
Focused on addressing takeaway capacity shortfall
Takeaway Capacity vs. Supply Outlook
(mmbpd)
SLIDE 6
0
100
200
300
400
500
600
700
2017 2018 2019 2020
Incremental WCSB Blended
Heavy Supply Growth (cumulative kbpd)
0
1
2
3
4
5
6
2016 2017 2018 2019 2020 2021 2022 2023 2024 2025
CAPP June 2016 Supply Forecast
Near term
optimization:
+60 – 80 kbpd
Western Canadian Refineries
Other Existing Pipelines
Enbridge
Strong Demand Drives High Pipeline Utilization
SLIDE 7
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
Q2 2016 Financial Summary
SLIDE 8
Adjusted EBITDA of $489.3 million +16% over Q2 2015
Earnings ($ millions, except per unit amounts)
2Q 2016 2Q 2015
Adjusted EBITDA1 $489.3 $422.4
Distributable Cash Flow2 $262.7 $231.6
Distribution Coverage2 1.00x 0.90x
Cash Coverage2,3 1.22x 1.07x
Debt/EBITDA4 4.6x 4.2x
Bank Covenant 4.2x 3.6x
Reconciliations to GAAP measures can be found in the supplemental package. 1 Adjusted EBITDA includes non-controlling interest. 2 Distributable cash flow and Coverage metric excludes deferred distribution attributable to preferred unitholders. 3 Cash coverage excludes Paid-in-Kind distribution. 4 MEP debt and MOLP EBITDA are deconsolidated, and EBITDA includes distributions received by EEP from MOLP and MEP for purposes of the Debt/EBITDA and Bank Covenant metrics. Debt/EBITDA metric considers 50% equity treatment for the
hybrid financing instruments. Bank Covenant considers 100% equity treatment for the hybrid financing instruments.
- Alberta wildfires ($20MM impact in Q2)
+ Higher Lakehead surcharge,
effective April 1
+ New projects in service
+ Higher Ozark system deliveries
+ Lower O&A expenses and power
2Q16 vs. 1Q16 Adjusted EBITDA
Q2 2016 Operational Highlights
SLIDE 9
2.17 2.19 2.33 2.21 2.34 2.39 2.74
2.44
0.19 0.22 0.20
0.22 0.22 0.21
0.17
0.22 0.35 0.36 0.34 0.37
0.33 0.38
0.40
0.38
-
0.50
1.00
1.50
2.00
2.50
3.00
3.50
3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16
Lakehead Mid-Continent North Dakota
Liquids Pipelines Volumes by System (MMbpd)
• Alberta wildfires impacted Lakehead deliveries 255 kbpd in May and June
• Lakehead deliveries have returned to anticipated levels
• Demand for our liquids pipeline systems remains strong
Capital and Investment Expenditures
SLIDE 10
Adequate liquidity to fund base capital program
2016 CAPITAL AND INVESTMENT EXPENDITURES
($ millions)
Eastern Access1 50
US Mainline Expansions1 60
Sandpiper1 75
Line 3 Replacement 160
Liquids Integrity 265
Liquids Other Growth Enhancements 190
Natural Gas Growth Projects2 20
Maintenance Capital Expenditures2 65
Total Capital Expenditures 885
Eastern Access call option exercise 360
Line 3 Replacement joint funding scenario3 (~350)
Capital and Investment Expenditures +/- 885
414
646
125
87
750
0
200
400
600
800
1,000
1,200
1,400
6/30/2016 3/31/2016
Credit Facilities Cash Pro-forma
$539
$1,289
$733
Available Liquidity ($ 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. 4 On July 26, 2016, EEP entered into an unsecured revolving 364-day credit agreement with Enbridge (U.S.) Inc.
Proforma: $750 million
364-day Credit Facility
with Enbridge (U.S.) Inc.4
Low-risk Business Model
<5% of business cash flows subject to direct commodity exposure
Contract structures deliver reliable 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 11
Cost of Service/Take-or-Pay
Fee for Service Commodity sensitive1 Investment Grade Non-Investment Grade
Commercial Structures Counterparty Credit Profile2
Key Takeaways
12
Business model attractive in all market conditions
Strong business fundamentals • 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
• Strategic review for investments in Midcoast Operating and MEP ongoing; expect resolution by the end of the year
Strong sponsor in Enbridge Inc.
Q&A
Supplemental Slides
July 28, 2016
Second Quarter 2016 Earnings Presentation
Second Quarter Earnings
SLIDE 15
(GAAP)
$ 324.5 $ 271.6 $ 52.9
(60.1) (277.6) 217.5
(2.7) (3.6) 0.9
261.7 (9.6) 271.3
6.7 6.0 0.7
13.3 17.3 (4.0)
(101.5) (78.0) (23.5)
(2.5) 3.8 (6.3)
177.7 (60.5) 238.2
70.3 10.0 60.3
22.5 22.5 -
1.2 4.1 (2.9)
83.7 (97.1) 180.8
$ 27.7 $ (149.4) $ 177.1
347.1 339.9 7.2
$ 0.08 $ (0.44) $ 0.52
(Unaudited; $ in millions, except per unit in dollars; average units in millions).
Quarter Ended June 30,
Income tax benefit (expense)
2016 2015 ChangeSegmented and corporate operating income (loss):
- Liquids
- Natural Gas
- Corporate
Other income
Operating income (loss)
Interest expense, net
Allowance for equity used during construction
Net income (loss)
Less: Net income attributable to:
Weighted average common units and i-units outstanding (basic and diluted)
Net income (loss) per common unit and i-unit (basic and diluted)
Noncontrolling Interest
Net income (loss) attributable to general and limited partner ownership in EEP
Net income (loss) allocable to common units and i-units
Series 1 preferred unit distributions
Accretion of discount on Series 1 preferred units
Second Quarter Earnings
SLIDE 16
(Adjusted)
$ 330.8 $ 270.6 $ 60.2
(3.7) 2.7 (6.4)
- Corporate (2.7) (3.6) 0.9
324.4 269.7 54.7
6.7 6.0 0.7
13.3 17.3 (4.0)
(100.0) (81.8) (18.2)
(2.5) 3.8 (6.3)
(83.8) (72.0) (11.8)
(22.5) (22.5) -
135.6 120.5 15.1
Allocations to general partner (57.0) (56.7) (0.3)
$ 78.6 $ 63.8 $ 14.8
Weighted average common units and i-units outstanding (millions) 347.1 339.9 7.2
Adjusted net income per common unit and i-unit (dollars) $ 0.22 $ 0.18 $ 0.04
Adjusted EBITDA (1)
$ 489.3 $ 422.4 $ 66.9
(1) Excludes the impact of: (a) non-cash, mark-to-market net gains and losses; (b) environmental costs, net of insurance recoveries,
associated with the Line 6B incident; (c) Line 2 hydrotest expenses, net of recoveries; (d) non-cash asset impairment; (e) non-cash
goodwill impairment; and other adjustments - see non-GAAP reconciliations.
Adjusted net income allocable to common units and i-units (1)
(Unaudited; $ in millions, except per unit in dollars; average units in millions)
Income tax benefit (expense)
Less: Net income attributable to:
Adjusted net income attributable to general and limited partner ownership in EEP(1)
Noncontrolling interest
Series 1 preferred unit distributions
Interest expense, net(1)
Quarter Ended June 30,
2016 2015 Change
Adjusted segmented operating income (loss):
- Liquids (1)
- Natural Gas (1)
Adjusted operating income(1)
Allowance for equity used during construction
Other income(1)
Distribution Coverage
SLIDE 17
Net income attributable to general and limited
partner ownership in EEP $ 83.7 $ 83.7 $ 163.7 $ 163.7
Noncash derivatives fair value losses 41.4 41.4 65.7 65.7
Accretion of discount on Series 1 preferred units 1.2 1.2 2.3 2.3
Make-up rights adjustment - - 1.0 1.0
Line 2 hydrotest expenses, net of recoveries 0.2 0.2 (8.3) (8.3)
1.0 1.0 16.0 16.0
Option premium amortization - - 0.9 0.9
Asset impairment 8.1 8.1 8.1 8.1
Adjusted net income 135.6 135.6 249.4 249.4
Series 1 preferred unit distributions 22.5 22.5 45.0 45.0
Depreciation and amortization 116.9 116.9 232.1 232.1
Distribution in excess of income from Joint Ventures 1.2 1.2 2.7 2.7
Maintenance capital expenditures (11.6) (11.6) (19.7) (19.7)
(1.0) (1.0) (1.4) (1.4)
Make-up rights adjustment (0.9) (0.9) (0.9) (0.9)
Distributable Cash Flow(2) $ 262.7 $ 262.7 $ 507.2 $ 507.2
Cash Distributions 216.1 216.0 432.1 432.0
46.4 45.2 91.6 88.8
Total Distributions $ 262.5 $ 261.2 $ 523.7 $ 520.8
Cash Coverage Ratio 1.22 1.22 1.17 1.17
Coverage Ratio 1.00 1.01 0.97 0.97
Distribution per unit $ 0.5830 $ 0.5830 $ 1.1660 $ 1.1660
(Unaudited; $ in millions)
(1)
(2) See non-GAAP reconciliation schedules.(3)
Notional value of paid in kind distributions.
YTD 2016 YTD 2016
Distribution agreement in place with MEP to support 1.0x coverage of the then declared distribution with a term through 2017, and no
requirement for MEP to reimburse EEP for adjusted distributions.
PIK Distributions (gross)(3)
Q2 2016 Q2 2016
Line 6A and 6B incident expenses, net of recoveries
Distribution support agreement(1)
Segment Operating Income (Loss)
SLIDE 18
(Adjusted)
Liquids
$ 625.8 $ 530.4 $ 95.4
(59.7) (57.2) (2.5)
0.9 0.8 0.1
(131.3) (114.7) (16.6)
(104.9) (88.7) (16.2)
Adjusted operating income(1) $ 330.8 $ 270.6 $ 60.2
(1)
Quarter Ended June 30,
Excludes the impact of: (a) non-cash, mark-to-market net gains and losses; (b) environmental costs, net of
insurance recoveries, associated with the Line 6B incident; (c) Line 2 hydrotest expenses, net of recoveries; and
other adjustments - see non-GAAP reconciliations.
(Unaudited; $ in millions)
Depreciation and amortization
Operating revenue(1)
Power(1)
Environmental costs(1)
Operating and administrative expenses (1)
Change20152016
Natural Gas
Gross Margin (1) $ 114.3 $ 130.8 $ (16.5)
Operating and administrative expenses (78.0) (87.3) 9.3
Depreciation and amortization (40.0) (40.8) 0.8
Adjusted operating income (loss) (1) $ (3.7) $ 2.7 $ (6.4)
(1) Excludes the impact of: (a) unrealized non-cash mark-to-market adjustments, (b) non-cash asset impairment; (c)
non-cash goodwill impairment; among other adjustments - see non-GAAP reconciliations.
Quarter Ended June 30,
20152016 Change
(Unaudited; $ in millions)
Liquids Operating Income
SLIDE 19
(Adjusted)
Liquids Adjusted Operating Income
$ 275.1 $ 214.2 $ 60.9
18.2 21.0 (2.8)
37.5 35.4 2.1
Liquids adjusted operating income(1) $ 330.8 $ 270.6 $ 60.2
(1)
Quarter Ended June 30,
Change
Excludes the impact of: (a) non-cash, mark-to-market net gains and losses; (b) environmental costs,
net of insurance recoveries, associated with the Line 6B incident; (c) Line 2 hydrotest expenses, net of
recoveries; and other adjustments - see non-GAAP reconciliations.
North Dakota
(Unaudited; $ in millions)
2016 2015
Lakehead
Mid-Continent
Lakehead Operating Income
SLIDE 20
(Adjusted)
Lakehead Adjusted Operating Income
$ 513.5 $ 420.0 $ 93.5
(49.3) (46.4) (2.9)
(98.9) (84.5) (14.4)
(90.2) (74.9) (15.3)
Adjusted operating income(1) $ 275.1 $ 214.2 $ 60.9
(1)
2016 2015
Operating revenue(1)
Power
Quarter Ended June 30,
Change
Operating and administrative expenses(1)
Depreciation and amortization
(Unaudited; $ in millions)
Excludes the impact of: (a) non-cash, mark-to-market net gains and losses; (b) environmental costs, net of
insurance recoveries, associated with the Line 6B incident; (c) Line 2 hydrotest expenses, net of recoveries; and
other adjustments - see non-GAAP reconciliations.
Mid-Continent Operating Income
SLIDE 21
(Adjusted)
Mid-Continent Adjusted Operating Income
$ 42.0 $ 41.9 $ 0.1
(2.5) (2.4) (0.1)
(16.1) (14.1) (2.0)
(5.2) (4.4) (0.8)
Adjusted operating income(1) $ 18.2 $ 21.0 $ (2.8)
(1) Excludes the impact of: (a) non-cash, mark-to-market net gains and losses - see non-GAAP reconciliations.
Operating and administrative expenses(1)
Depreciation and amortization
(Unaudited; $ in millions)
Quarter Ended June 30,
Change2016 2015
Operating revenue(1)
Power
North Dakota Operating Income
SLIDE 22
(Adjusted)
North Dakota Adjusted Operating Income
$ 70.3 $ 68.5 $ 1.8
(7.9) (8.4) 0.5
(15.4) (15.3) (0.1)
(9.5) (9.4) (0.1)
Adjusted operating income(1) $ 37.5 $ 35.4 $ 2.1
(1) Excludes the impact of: (a) non-cash, mark-to-market net gains and losses - see non-GAAP reconciliations.
Operating and administrative expenses(1)
Depreciation and amortization
(Unaudited; $ in millions)
Quarter Ended June 30,
Change2016 2015
Operating revenue(1)
Power
Line 6B and Line 6A Incidents
SLIDE 23
Amounts in millions of dollars.
Civil penalty under the
Clean Water Act of U.S.
$61.0 Civil penalty under the
Clean Water Act of U.S.
$93.7 Long-term monitoring
• Mix of capital and expense items
• Items largely consistent with ongoing integrity
program
Line 6B
Total cost estimate accrued 1,223.0
Spent through 06/30/2016 1,068.3
Remaining liability 154.7
Line 6A
Total cost estimate accrued 52.0
Spent through 06/30/2016 51.0
Remaining liability 1.0
Insurance
Coverage 650.0
Proceeds collected through 06/30/2016 547.0
Remaining balance eligible for recovery 103.0
Injunctive Safety Measures
Estimated cost over 4-year term of decree 110.0
Capital Expenditures
SLIDE 24
Maintenance Capex $ 15.2 $ 27.2
Enhancement Capex (1)(2) $ 202.4 $ 472.4
Ending PP&E, net $ 17,643.0 $ 17,643.0
Q2 2016 Major Enhancement Expenditures
North Dakota Expansions (1) $ 35.8 $ 71.6
Eastern Access (2) $ 56.6 $ 127.5
Mainline Expansion (2) $ 35.8 $ 74.8
(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.
Q2 2016 YTD 2016
Q2 2016 YTD 2016
(Unaudited; $ in millions)
Book Capitalization
SLIDE 25
6/30/2016 12/31/2015
Short-term debt $ 299.9 $ 300.0
Long-term debt(1) 8,013.9 7,528.4
Total Debt $ 8,313.8 $ 7,828.4
Partners' capital(1) 9,403.4 9,482.1
Total Capitalization $ 17,717.2 $ 17,310.5
Total Debt / Total Capitalization 47% 45%
6/30/2016 12/31/2015
Amounts outstanding under Credit Facilities $ 1,740.0 $ 1,110.0
Principal amount of Commercial Paper issuances 194.3 326.1
Letters of Credit outstanding 251.6 121.7
Amount we could borrow 414.1 1,042.2
Total credit available under Credit Facilities (2) $ 2,600.0 $ 2,600.0
(Unaudited; $ in millions)
(1)
(2)
Debt reduced and Partners' Capital increased in 2016 and 2015 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.
Volume History
SLIDE 26
Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2
2014 2014 2014 2015 2015 2015 2015 2016 2016
Liquids Business - Volumes (kbpd)
Lakehead 2,088 2,172 2,187 2,330 2,208 2,338 2,388 2,735 2,440
Mid-Continent 176 191 222 199 221 216 213 168 216
North Dakota 314 347 362 342 365 333 375 402 381
Total 2,578 2,710 2,771 2,871 2,794 2,887 2,976 3,305 3,037
East Texas 1,029 1,063 1,056 1,007 968 966 915 948 931
Anadarko 819 806 858 831 794 760 707 652 637
North Texas 300 304 297 287 274 262 239 216 203
Total 2,148 2,173 2,211 2,125 2,036 1,988 1,861 1,816 1,771
East Texas 447 426 423 444 465 519 510 509 505
Anadarko 637 664 793 809 736 682 631 585 590
North Texas 199 202 192 188 185 173 161 142 131
Total 1,283 1,292 1,408 1,441 1,386 1,374 1,302 1,236 1,226
NGL Production -Volumes (bpd)
Total 83,480 84,121 86,136 81,046 81,056 85,343 79,064 73,499 71,747
Natural Gas Business - Volumes ('000 MMbtu/d)
Natural Gas Processing - Volumes ('000 mcf/d)
Estimated Commodity Positions (July – December 2016)
SLIDE 27
Gas segment commodity-based gross margin >90% hedged for 2016
(1) Represents Estimated Commodity Positions for the Gathering, Processing and Transportation Segment of Midcoast Operating, L.P. for July– December 2016. Unaudited, $ in millions.
(2) Options valued at their strike prices to determine hedged cash flows.
Hedge Weighted Avg
Hedged Cash
Flows (2)
% Hedge Price $ MM
Natural Gas (24,940) MMbtu/d 0% 0 $0.00 /MMbtu $0.0
C2 11,815 bpd 0% 0 $0.00 /gallon $0.0
C3 4,622 bpd 100% 4,600 $0.85 /gallon $30.3
iC4 889 bpd 56% 500 $0.93 /gallon $3.6
C4 1,320 bpd 114% 1,500 $1.06 /gallon $12.2
C5 1,362 bpd 62% 850 $1.22 /gallon $8.0
Total NGLs 20,009 bpd 37% 7,450 $54.1
Condensate 2,781 bpd 79% 2,200 $75.91/barrel $30.7
Hedged Commodity Gross Margin $84.9
Eq
uit
y L
en
gth
Volume
2016 Estimated Commodity Positions (1)
Physical Hedged
Non-GAAP
Reconciliations
Non-GAAP measures no longer include make-up rights and option premium amortization adjustments. These
changes will be made on a prospective basis and are not material for historical periods presented.
Adjusted Earnings
SLIDE 29
• The foregoing presentation makes reference to adjusted net income in order to exclude
the effect of non-cash and other items that are not indicative of our core operating
results. A reconciliation to net income per GAAP is provided below.
$ 83.7 $ (97.1) $ 163.7 $ 43.0
-Liquids 5.1 8.3 6.8 12.2
-Natural Gas 34.8 18.7 55.5 45.4
-Corporate 1.5 (3.8) 3.4 (32.4)
1.2 4.1 2.3 8.0
- (3.2) 1.0 (5.8)
0.2 (6.1) (8.3) (5.7)
1.0 - 16.0 -
- (2.6) 0.9 (3.6)
- 192.8 - 192.8
8.1 9.4 8.1 9.4
135.6 120.5 249.4 263.3
57.0 56.7 113.6 110.9
$ 78.6 $ 63.8 $ 135.8 $ 152.4
347.1 339.9 345.9 336.3
$ 0.22 $ 0.18 $ 0.39 $ 0.46
FY 2016 FY 2015Q2 2016 Q2 2015
Make-up rights adjustment
Line 2 hydrotest expenses, net of recoveries
Noncash derivative fair value losses (gains)
Accretion of discount on Series 1 preferred units
Net income (loss) attributable to general and limited partner ownership
(unaudited; dollars in millions except per unit amounts)
Line 6A and 6B incident expenses, net of recoveries
Asset impairment
Goodwill impairment
Less: Allocations to general partner
Adjusted net income allocable to common units and i-units
Weighted average common units and i-units outstanding (millions)
Adjusted net income per common unit and i-unit (dollars)
Option premium amortization
Adjusted net income
Adjusted Segment Operating Income (Loss)
SLIDE 30
• The foregoing presentation makes reference to adjusted operating income (loss),
which is reconciled to nearest comparable GAAP measures as shown below.
$ 324.5 $ 271.6 $ (60.1) $ (277.6)
5.1 8.3 45.8 24.6
- (3.2) - -
- - - (3.3)
0.2 (6.1) - -
1.0 - - -
- - 10.6 12.3
- - - 246.7
$ 330.8 $ 270.6 $ (3.7) $ 2.7
(Unaudited; $ in millions)
Line 2 hydrotest expenses, net of recoveries
Operating income (loss)
Noncash derivative fair value losses
Make-up rights adjustment
Option premium amortization
Natural Gas
Q2 2016 Q2 2015 Q2 2016 Q2 2015
Liquids
Line 6A and 6B incident expenses, net of recoveries
Goodwill impairment
Adjusted operating income (loss)
Asset impairment
Adjusted Gross Margin
SLIDE 31
• The foregoing presentation makes reference to gross margin for the Natural Gas
segment, which is reconciled to nearest comparable GAAP measures as shown below.
$ 427.6 $ 780.1
(359.1) (670.6)
45.8 24.6
- (3.3)
$ 114.3 $ 130.8
(Unaudited; $ in millions)
Adjusted gross margin
Natural Gas Q2 2016 Q2 2015
Operating revenues
Commodity costs
Noncash derivative fair value losses
Option premium amortization
Adjusted EBITDA
SLIDE 32
• The foregoing presentation makes reference to adjusted EBITDA which is used as a
supplemental financial measurement to manage the performance of the entity. A
reconciliation of net income (loss) to adjusted EBITDA is provided below.
$ 83.7 $ (97.1) $ 163.7 $ 43.0
144.9 129.5 285.8 257.9
101.5 78.0 214.4 126.3
2.5 (3.8) 5.0 (1.4)
70.3 10.0 139.1 61.3
22.5 22.5 45.0 45.0
50.9 32.9 79.7 71.9
1.2 4.1 2.3 8.0
- (3.3) 1.0 (6.0)
0.2 (6.1) (8.3) (5.7)
1.0 - 16.0 -
- (3.3) 1.2 (4.7)
- 246.7 - 246.7
10.6 12.3 10.6 12.3
$ 489.3 $ 422.4 $ 955.5 $ 854.6 Adjusted EBITDA
Net income (loss) attributable to general and limited partner
ownership interests in Enbridge Energy Partners, L.P.
Depreciation and amortization
Noncash derivative fair value losses
Goodwill impairment
Interest expense, net
Make-up rights adjustment
Asset impairment
Income tax expense (benefit)
Option premium amortization
Net income attributable to noncontrolling interest
Accretion of discount on Series 1 preferred units
Series 1 preferred unit distributions
Six months ended
June 30,
2016
Three months ended
2015 2015(unaudited; dollars in millions) 2016
Adjusted EBITDA June 30,
Line 6A and 6B incident expenses, net of recoveries
Line 2 hydrotest expense, net of recoveries
Distributable Cash Flow
SLIDE 33
$ 280.2 $ 266.4 $ 546.5 $ 646.9
104.9 71.1 194.0 28.5
13.3 17.3 25.6 40.3
- (3.3) 1.2 (4.7)
0.2 (6.1) (8.3) (5.7)
1.2 1.9 2.7 3.4
(11.6) (17.7) (19.7) (33.8)
(118.5) (97.0) (226.3) (181.6)
(1.0) - (1.4) -
(6.0) (1.0) (7.1) (8.0)
$ 262.7 $ 231.6 $ 507.2 $ 485.3
(1)
Six months ended
June 30,
2016 2015
Line 2 hydrotest expense, net of recoveries
Three months ended
Distributable Cash Flow June 30,
(unaudited; dollars in millions) 2016 2015
Net cash provided by operating activities
Changes in operating assets and liabilities,
net of cash acquired
Allowance for equity used during construction
Option premium amortization
Distribution agreement in place w ith MEP to support 1.0x coverage of the then declared distribution w ith a term through 2017, and no requirement
for MEP to reimburse EEP for adjusted distributions.
Other
Distributable cash flow
Distributions in excess of equity earnings
Maintenance capital expenditures
Distribution support agreement(1)Non-controlling interests
• The foregoing presentation makes reference to distributable cash flow, 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 distributable cash flow is provided below.
Adjusted EBITDA to DCF
SLIDE 34
$ 489.3 $ 422.4 $ 955.5 $ 854.6
(93.3) (81.8) (197.7) (158.7)
(2.5) 3.8 (5.0) 1.4
1.2 1.9 2.7 3.4
Maintenance capital expenditures (11.6) (17.7) (19.7) (33.8)
(118.5) (97.0) (226.3) (181.6)
(0.9) - (0.9) -
(1.0) - (1.4) -
$ 262.7 $ 231.6 $ 507.2 $ 485.3
(1)
(2)
(unaudited; dollars in millions) 2016 2015 2016 2015
Three months ended Six months ended
Distributable Cash Flow June 30, June 30,
Distribution agreement in place w ith MEP to support 1.0x coverage of the then declared distribution w ith a term through 2017, and no
requirement for MEP to reimburse EEP for adjusted distributions.
Adjusted EBITDA
Interest expense, net(1)
Income tax benefit (expense)
Distributions in excess of equity earnings
Non-controlling interests
Make-up rights adjustment
Distribution support agreement(2)
Distributable cash flow
Excludes unrealized mark-to-market net losses of $1.5 million and $3.4 million for the three and six months ended June 30, 2016,
respectively. Excludes unrealized mark-to-market net gains of $3.8 million and $32.4 million for the three and six months ended June 30,
2015, respectively. Also excludes $6.7 million and $13.3 million of amortization related to pre-issuance interest sw aps for the three and
six months ended June 30, 2016.
• A reconciliation of adjusted EBITDA to distributable cash flow is provided below.