Third Quarter 2016
Earnings Presentation
October 31, 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 ability of the Partnership or its joint venture partners, as applicable, to successfully complete and finance projects, including the Bakken Pipeline transaction; (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 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. Bakken Pipeline System
2. Financial Summary
3. Low-Risk Business Model
4. Question & Answer
Bakken Pipeline Investment
SLIDE 4
Another important link in market access strategy
1 An independent committee of the board of directors of the delegate of EEP’s general partner and Enbridge Energy Company, Inc. (EECI), a wholly owned subsidiary of Enbridge Inc. (ENB), have reached a tentative agreement on the terms of an arrangement through which each party would fund the acquisition of and participate in the returns generated by the investment in the Bakken Pipeline System.
Strategic Fit
• Offers customers competitive tolls between the Bakken and USGC
• Joint toll opportunity with Enbridge mainline
• Highly contracted: secured by long-term take-or-pay commitments
• High credit quality counterparties: >90% investment grade
• Expansion opportunities
Funding Plan
• Anticipate that the investment will be funded 25% by EEP
and 75% by ENB1
• EEP would issue a new class of limited partner units to
ENB to substantially fund its 25% investment (PIK feature)
• Joint funding arrangement would provide for a call option
for EEP to upsize its interest by 15%, at original cost
Q3 2016 Financial Summary
SLIDE 5
FY adjusted EBITDA guidance $1.8 - $1.9 billion; FY DCF guidance $860 - $920 million
Earnings ($ millions, except per unit amounts)
3Q 2016 3Q 2015
Adjusted EBITDA1 $456.8 $460.7
Distributable Cash Flow2 $214.7 $248.8
Distribution Coverage2 0.81x 0.96x
Cash Coverage2,3 0.99x 1.15x
Debt/EBITDA4 4.4x 4.2x
Bank Covenant 4.0x 3.8x
Reconciliations to GAAP measures can be found in the supplemental package. 1 Adjusted EBITDA includes non-controlling interest. 2 Distributable cash flow and Coverage metric excludes deferred distribution attributable to preferred unitholders. 3 Cash coverage excludes Paid-in-Kind distribution. 4 MEP debt and MOLP EBITDA are deconsolidated, and EBITDA includes distributions received by EEP from MOLP and MEP for purposes of the Debt/EBITDA and Bank Covenant metrics. Debt/EBITDA metric considers 50% equity
treatment for the hybrid financing instruments. Bank Covenant considers 100% equity treatment for the hybrid financing instruments.
3Q16 vs. 3Q15 DCF Analysis:
Higher liquids segment revenues
- Lower gas segment earnings
- Higher interest expense (Oct’ 15 debt issuance)
3Q16 vs. 2Q16 DCF Analysis:
Higher liquids segment revenues
- Seasonally higher operating expenses and maintenance capital
- Higher power costs
On track to achieve near the top-end of FY adjusted EBITDA and DCF guidance
Q3 2016 Operational Highlights
SLIDE 6
2.19 2.33 2.21 2.34 2.39 2.74
2.44 2.50
0.22 0.20
0.22 0.22 0.21
0.17
0.22 0.22 0.36 0.34 0.37
0.33 0.38
0.40
0.38 0.36
-
0.50
1.00
1.50
2.00
2.50
3.00
3.50
4Q14 1Q15 2Q15 3Q15 4Q15 1Q16 2Q16 3Q16
Lakehead Mid-Continent North Dakota
Liquids Pipelines Volumes by System (MMbpd)
• Lakehead deliveries have strengthened following northeastern Alberta wildfires
• Q3 Lakehead deliveries affected by seasonal upstream and downstream refinery turnarounds
• Heavy lines remain oversubscribed
Demand for our liquids pipeline systems remains strong
Capital Expenditures
SLIDE 7
Adequate liquidity to fund base capital program
2016 CAPITAL EXPENDITURES
($ millions)
Eastern Access1 50
US Mainline Expansions1 50
Sandpiper1,2 45
Line 3 Replacement 100
Liquids Integrity 180
Liquids Other Growth Enhancements 190
Natural Gas Growth Projects3 15
Maintenance Capital Expenditures3 70
Total Capital Expenditures 700
1,172
414
41
125
0
200
400
600
800
1,000
1,200
1,400
9/30/2016 6/30/2016
Credit Facilities Cash
$1,213
$539
Available Liquidity ($ 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 In connection with the long term deferral of Sandpiper, we evaluated the project for impairment and recognized an impairment charge of $757 million, resulting in a net earnings impact of $489 million after deducting non-controlling interest. For further details, see our
Quarterly Report on Form 10Q filed with the SEC for the three months ended September 30, 2016. 3 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.
SLIDE 8
Delivering stable cash flows
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
Strong sponsor in Enbridge Inc.
Attractive Business Model
Key Takeaways
• Core liquids pipelines business performing well
• On track to achieve near the top-end of previously communicated FY16 adjusted EBITDA and DCF guidance
• Pending acquisition of equity interest in Bakken Pipeline System
• Progressing strategic review
SLIDE 9
Q&A
Supplemental Slides
October 31, 2016
Third Quarter 2016 Earnings Presentation
Third Quarter Earnings
SLIDE 12
(GAAP)
$ (446.8) $ 253.1 $ (699.9)
(28.9) 5.0 (33.9)
(3.2) (3.3) 0.1
(478.9) 254.8 (733.7)
8.7 8.8 (0.1)
10.1 13.7 (3.6)
(112.3) (88.2) (24.1)
(2.2) (4.6) 2.4
(574.6) 184.5 (759.1)
(191.9) 77.8 (269.7)
22.5 22.5 -
1.2 2.1 (0.9)
(406.4) 82.1 (488.5)
$ (452.6) $ 26.1 $ (478.7)
349.1 341.1 8.0
$ (1.31) $ 0.07 $ (1.38)
(Unaudited; in millions, except per unit amounts).
Quarter Ended September 30,
Income tax 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 (loss) 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
Third Quarter Earnings
SLIDE 13
(Adjusted)
$ 304.0 $ 295.1 $ 8.9
(11.4) 9.9 (21.3)
- Corporate (3.2) (3.3) 0.1
289.4 301.7 (12.3)
8.7 8.4 0.3
10.1 13.7 (3.6)
(112.3) (80.5) (31.8)
(2.2) (4.6) 2.4
(81.9) (78.8) (3.1)
(22.5) (22.5) -
89.3 137.4 (48.1)
Allocations to general partner (56.1) (57.1) 1.0
$ 33.2 $ 80.3 $ (47.1)
Weighted average common units and i-units outstanding 349.1 341.1 8.0
Net income per common unit and i-unit (dollars per unit) $ 0.09 $ 0.23 $ (0.14)
EBITDA (1) $ 456.8 $ 460.7 $ (3.9)
(1) Excludes the impact of: (a) non-cash, mark-to-market net gains and losses; (b) asset impairment; (c) environmental
costs, net of insurance recoveries, associated with the Line 6A & 6B incidents; (d) Line 2 hydrotest expenses, net of
recoveries; and other adjustments - see non-GAAP reconciliations.
Net income allocable to common units and i-units (1)
(Unaudited; in millions, except per unit amounts)
Income tax expense
Less: Net income attributable to:
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 September 30,
2016 2015 Change
Segmented operating income (loss):
- Liquids (1)
- Natural Gas (1)
Operating income(1)
Allowance for equity used during construction
Other income(1)
Distribution Coverage
SLIDE 14
Net loss attributable to general and limited
partner ownership in EEP $ (406.4) $ (406.4) $ (242.7) $ (242.7)
Noncash derivatives fair value losses 11.3 11.3 77.0 77.0
Accretion of discount on Series 1 preferred units 1.2 1.2 3.5 3.5
Make-up rights adjustment - - 1.0 1.0
Line 2 hydrotest expenses, net of recoveries (2.0) (2.0) (10.3) (10.3)
(10.0) (10.0) 6.0 6.0
Option premium amortization - - 0.9 0.9
Loss on sale of non-core assets and severance 2.2 2.2 2.2 2.2
Sandpiper costs 3.7 3.7 3.7 3.7
489.3 489.3 497.4 497.4
Adjusted net income 89.3 89.3 338.7 338.7
Series 1 preferred unit distributions 22.5 22.5 67.5 67.5
Depreciation and amortization 118.0 118.0 350.1 350.1
Distribution in excess of income from Joint Ventures 3.0 3.0 5.7 5.7
Maintenance capital expenditures (15.8) (15.8) (35.5) (35.5)
(2.4) (2.4) (3.8) (3.8)
Make-up rights adjustment 0.1 0.1 (0.8) (0.8)
Distributable Cash Flow(2) $ 214.7 $ 214.7 $ 721.9 $ 721.9
Cash Distributions 216.1 216.1 648.2 648.1
47.6 46.4 139.2 135.2
Total Distributions $ 263.7 $ 262.5 $ 787.4 $ 783.3
Cash Coverage Ratio 0.99 0.99 1.11 1.11
Coverage Ratio 0.81 0.82 0.92 0.92
Distribution per unit $ 0.5830 $ 0.5830 $ 1.7490 $ 1.7490
(Unaudited; in millions, except per unit amounts)
(1)
(2) See non-GAAP reconciliation tables.(3)
Notional value of paid in kind distributions.
As paid
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)
Asset impairment
As declared As paid
Q3 2016 Q3 2016
Line 6A and 6B incident expenses, net of recoveries
Distribution support agreement(1)
As declared
Segment Operating Income (Loss)
SLIDE 15
(Adjusted)
Natural Gas
Gross Margin (1) $ 96.6 $ 138.7 $ (42.1)
Operating and administrative expenses (68.8) (89.6) 20.8
Depreciation and amortization (39.2) (39.2) 0.0
Adjusted operating income (loss) (1) $ (11.4) $ 9.9 $ (21.3)
(1) Excludes the impact of unrealized non-cash mark-to-market adjustments, among other adjustments - see non-
GAAP reconciliations.
Quarter Ended September 30,
20152016 Change
(Unaudited; in millions)
Liquids
$ 634.2 $ 597.4 $ 36.8
(74.3) (71.6) (2.7)
(146.5) (133.0) (13.5)
(109.4) (97.7) (11.7)
Adjusted operating income(1) $ 304.0 $ 295.1 $ 8.9
(1)
Operating revenue(1)
Power(1)
Quarter Ended September 30,
2016 2015 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.
Liquids Operating Income
SLIDE 16
(Adjusted)
Liquids Adjusted Operating Income
$ 252.1 $ 242.7 $ 9.4
20.5 16.2 4.3
31.4 36.2 (4.8)
Liquids adjusted operating income(1) $ 304.0 $ 295.1 $ 8.9
(1)
Quarter Ended September 30,
Change
Excludes the impact of: (a) non-cash, mark-to-market net gains and losses; (b) asset impairment; (c)
environmental costs, net of insurance recoveries, associated with the Line 6A & 6B incidents; (d) 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 17
(Adjusted)
Lakehead Adjusted Operating Income
$ 524.8 $ 482.9 $ 41.9
(63.1) (60.4) (2.7)
(115.1) (98.5) (16.6)
(94.5) (81.3) (13.2)
Adjusted operating income(1) $ 252.1 $ 242.7 $ 9.4
(1)
Quarter Ended September 30,
2016 2015
Operating revenue(1)
Power
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 6A & 6B incidents; (c) Line 2 hydrotest expenses, net of recoveries;
and other adjustments - see non-GAAP reconciliations.
Change
Operating and administrative expenses(1)
Depreciation and amortization
(Unaudited; in millions)
Mid-Continent Operating Income
SLIDE 18
(Adjusted)
Mid-Continent Adjusted Operating Income
$ 42.9 $ 40.1 $ 2.8
(2.6) (3.0) 0.4
(14.4) (16.2) 1.8
(5.4) (4.7) (0.7)
Adjusted operating income(1) $ 20.5 $ 16.2 $ 4.3
(1)
Quarter Ended September 30,
Excludes the impact of non-cash, mark-to-market net gains and losses - see non-GAAP reconciliations.
Operating and administrative expenses(1)
Depreciation and amortization
(Unaudited; in millions)
Change2016 2015
Operating revenue(1)
Power
North Dakota Operating Income
SLIDE 19
(Adjusted)
North Dakota Adjusted Operating Income
$ 66.5 $ 74.4 $ (7.9)
(8.6) (8.2) (0.4)
(17.0) (18.3) 1.3
(9.5) (11.7) 2.2
Adjusted operating income(1) $ 31.4 $ 36.2 $ (4.8)
(1)
Quarter Ended September 30,
Excludes the impact of non-cash, mark-to-market net gains and losses and asset impairment - see non-GAAP
reconciliations.
Operating and administrative expenses(1)
Depreciation and amortization
(Unaudited; in millions)
Change2016 2015
Operating revenue(1)
Power
Capital Expenditures
SLIDE 20
Maintenance Capex $ 18.9 $ 46.1
Enhancement Capex (1)(2) $ 178.1 $ 650.5
Ending PP&E, net $ 16,894.0 $ 16,894.0
Q3 2016 Major Enhancement Expenditures
North Dakota Expansions (1) $ 14.9 $ 86.5
Eastern Access (2) $ 24.2 $ 151.7
Mainline Expansion (2) $ 42.2 $ 117.0
(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.
Q3 2016 YTD 2016
Q3 2016 YTD 2016
(Unaudited; in millions)
Book Capitalization
SLIDE 21
9/30/2016 12/31/2015
Short-term debt $ 300.0 $ 300.0
Long-term debt(1)
8,008.4 7,528.4
Total Debt $ 8,308.4 $ 7,828.4
Partners' capital(1)
8,496.0 9,482.1
Total Capitalization $ 16,804.4 $ 17,310.5
Total Debt / Total Capitalization 49% 45%
9/30/2016 12/31/2015
Amounts outstanding under Credit Facilities $ 1,660.0 $ 1,110.0
Principal amount of Commercial Paper issuances 292.6 326.1
Letters of Credit outstanding 250.2 121.7
Amount we could borrow 1,172.2 1,042.2
Total credit available under Credit Facilities (2)
$ 3,375.0 $ 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 22
Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3
2014 2014 2015 2015 2015 2015 2016 2016 2016
Liquids Business - Volumes (kbpd)
Lakehead 2,172 2,187 2,330 2,208 2,338 2,388 2,735 2,440 2,495
Mid-Continent 191 222 199 221 216 213 168 216 217
North Dakota 347 362 342 365 333 375 402 381 363
Total 2,710 2,771 2,871 2,794 2,887 2,976 3,305 3,037 3,075
East Texas 1,063 1,056 1,007 968 966 915 948 931 894
Anadarko 806 858 831 794 760 707 652 637 606
North Texas 304 297 287 274 262 239 214 201 192
Total 2,173 2,211 2,125 2,036 1,988 1,861 1,814 1,769 1,692
East Texas 426 423 444 465 519 510 509 505 447
Anadarko 664 793 809 736 682 631 585 590 564
North Texas 202 192 188 185 173 161 142 131 125
Total 1,292 1,408 1,441 1,386 1,374 1,302 1,236 1,226 1,136
NGL Production -Volumes (bpd)
Total 84,121 86,136 81,046 81,056 85,343 79,064 73,499 71,747 67,588
Natural Gas Business - Volumes ('000 MMbtu/d)
Natural Gas Processing - Volumes ('000 mcf/d)
Estimated Commodity Positions (Oct – Dec 2016)
SLIDE 23
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 October – 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 (29,541) MMbtu/d 0% 0 $0.00 /MMbtu $0.0
C2 12,086 bpd 0% 0 $0.00 /gallon $0.0
C3 5,030 bpd 91% 4,600 $0.85 /gallon $15.1
iC4 967 bpd 52% 500 $0.93 /gallon $1.8
C4 1,342 bpd 112% 1,500 $1.06 /gallon $6.1
C5 1,326 bpd 64% 850 $1.22 /gallon $4.0
Total NGLs 20,751 bpd 36% 7,450 $27.1
Condensate 2,516 bpd 87% 2,200 $75.91/barrel $15.4
Hedged Commodity Gross Margin $42.4
Eq
uit
y L
en
gth
Volume
2016 Commodity Hedge Value (1)
Physical Hedged
Non-GAAP
Reconciliations
Reconciliations of forward looking non-GAAP financial measures to comparable GAAP measures are not
available due to the challenges with estimating some of the items, particularly with estimating non-cash
unrealized derivative fair value losses and gains, which are subject to market variability, and therefore a
reconciliation is not available without unreasonable effort. Non-GAAP measures no longer include make-up rights
and option premium amortization adjustments. These changes were made on a prospective basis beginning with
the second quarter of 2016 and are not material for historical periods presented.
$ (406.4) $ 82.1 $ (242.7) $ 125.1
-Liquids 0.2 (1.1) 7.0 11.1
-Natural Gas 11.1 (5.9) 66.6 39.5
-Corporate - 7.7 3.4 (24.7)
1.2 2.1 3.5 10.1
- - 1.0 (5.8)
(2.0) 42.8 (10.3) 37.1
(10.0) - 6.0 -
- (0.6) 0.9 (4.2)
2.2 2.4 2.2 2.4
- 7.9 - 7.9
Sandpiper costs 3.7 - 3.7 -
- - - 192.8
489.3 - 497.4 9.4
89.3 137.4 338.7 400.7
56.1 57.1 169.7 168.0
$ 33.2 $ 80.3 $ 169.0 $ 232.7
349.1 341.1 347.0 337.9
$ 0.09 $ 0.23 $ 0.48 $ 0.69
(unaudited; 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
Adjusted net income per common unit and i-unit (dollars per unit)
Option premium amortization
Adjusted net income
Loss on sale of non-core assets and severance
Loss on natural gas contracts assignment
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
FY 2016 FY 2015Q3 2016 Q3 2015
Adjusted Earnings
SLIDE 25
• 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 (loss) per GAAP is provided below.
Adjusted Segment Operating Income (Loss)
SLIDE 26
• The foregoing presentation makes reference to adjusted operating income (loss),
which is reconciled to nearest comparable GAAP measures as shown below.
$ (446.8) $ 253.1 $ (28.9) $ 5.0
0.2 (1.1) 14.6 (7.7)
- 0.3 - -
- - - (0.9)
(2.0) 42.8 - -
(10.0) - - -
- - 2.9 3.2
- - - 10.3
Sandpiper costs 5.9 - -
Asset impairment 756.7 - - -
$ 304.0 $ 295.1 $ (11.4) $ 9.9
(Unaudited; in millions)
Line 6A and 6B incident expenses, net of recoveries
Loss on natural gas contracts assignment
Adjusted operating income (loss)
Loss on sale of non-core assets and severance
Natural Gas
Q3 2016 Q3 2015 Q3 2016 Q3 2015
Liquids
Line 2 hydrotest expenses, net of recoveries
Operating income (loss)
Noncash derivative fair value losses (gains)
Make-up rights adjustment
Option premium amortization
Adjusted Gross Margin
SLIDE 27
• The foregoing presentation makes reference to gross margin for the Natural Gas
segment, which is reconciled to nearest comparable GAAP measures as shown below.
$ 486.0 $ 661.0
(404.0) (522.7)
14.6 (7.7)
- (0.9)
Loss on natural gas contracts assignment - 9.0
$ 96.6 $ 138.7
(Unaudited; in millions)
Adjusted gross margin
Natural Gas Q3 2016 Q3 2015
Operating revenues
Commodity costs
Noncash derivative fair value losses (gains)
Option premium amortization
Adjusted EBITDA
SLIDE 28
• 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.
$ (406.4) $ 82.1 $ (242.7) $ 125.1
148.6 136.9 434.4 394.8
112.3 88.2 326.7 214.5
2.2 4.6 7.2 3.2
(191.9) 77.8 (52.8) 139.1
22.5 22.5 67.5 67.5
14.8 (8.8) 94.5 63.0
1.2 2.1 3.5 10.1
- - 1.0 (6.0)
(2.0) 42.8 (10.3) 37.1
(10.0) - 6.0 -
- (0.9) 1.2 (5.6)
2.9 3.2 2.9 3.2
- 10.3 - 10.3
Sandpiper costs 5.9 - 5.9 -
- - - 246.7
756.7 - 767.3 12.3
Other - (0.1) - -
$ 456.8 $ 460.7 $ 1,412.3 $ 1,315.3
(unaudited; in millions) 2016
Adjusted EBITDA September 30,
Line 6A and 6B incident expenses, net of recoveries
Line 2 hydrotest expense, net of recoveries
Nine months ended
September 30,
2016
Three months ended
2015 2015
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 (gains)
Goodwill impairment
Interest expense, net
Make-up rights adjustment
Asset impairment
Income tax expense
Option premium amortization
Net income (loss) attributable to noncontrolling interest
Accretion of discount on Series 1 preferred units
Series 1 preferred unit distributions
Loss on sale of non-core assets and severance
Loss on natural gas contracts assignment
Distributable Cash Flow
SLIDE 29
• 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.
$ 414.6 $ 407.4 $ 961.1 $ 1,054.3
(73.3) (88.2) 120.7 (59.7)
10.1 13.7 35.7 54.0
- (0.9) 1.2 (5.6)
(2.0) 42.8 (10.3) 37.1
3.0 1.5 5.7 4.9
(15.8) (18.9) (35.5) (52.7)
(119.1) (109.4) (345.4) (291.0)
(2.4) - (3.8) -
(0.4) 0.8 (7.5) (7.2)
$ 214.7 $ 248.8 $ 721.9 $ 734.1
(1) 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
Nine months ended
September 30,
2016 2015
Line 2 hydrotest expense, net of recoveries
Three months ended
Distributable Cash Flow September 30,
(unaudited; 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
Adjusted EBITDA to DCF
SLIDE 30
• A reconciliation of adjusted EBITDA to distributable cash flow is provided below.
$ 456.8 $ 460.7 $ 1,412.3 $ 1,315.3
(105.7) (80.5) (303.4) (239.2)
(2.2) (4.6) (7.2) (3.2)
3.0 1.5 5.7 4.9
Maintenance capital expenditures (15.8) (18.9) (35.5) (52.7)
(119.1) (109.4) (345.4) (291.0)
0.1 - (0.8) -
(2.4) - (3.8) -
$ 214.7 $ 248.8 $ 721.9 $ 734.1
(1)
(2) 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 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 $3.4 million for the nine months ended September 30, 2016, respectively. Excludes
unrealized mark-to-market net losses of $7.7 million and net gains of $24.7 million for the three and nine months ended September 30,
2015, respectively. Also excludes $6.6 million and $19.9 million of amortization related to pre-issuance interest sw aps for the three and
nine months ended September 30, 2016.
Three months ended Nine months ended
Distributable Cash Flow September 30, September 30,
(unaudited; in millions) 2016 2015 2016 2015