third quarter 2016 earnings presentation - enbridge/media/eepeeqmep...q3 2016 financial summary...

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.

http://www.sec.gov/

http://www.sec.gov/

http://www.sec.gov/

http://www.sec.gov/

http://www.sec.gov/

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.

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

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


Interest expense, net(1)


2016 2015 Change

Segmented operating income (loss):

- Liquids (1)

- Natural Gas (1)

Operating income(1)


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.


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)


2016 2015 Change

Operating and administrative expenses(1)

Depreciation and amortization


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)


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


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)


(1)


2016 2015


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




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)


(1)


Excludes the impact of non-cash, mark-to-market net gains and losses - see non-GAAP reconciliations.




Change2016 2015


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)


Excludes the impact of non-cash, mark-to-market net gains and losses and asset impairment - see non-GAAP

reconciliations.




Change2016 2015


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


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


(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)


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)


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




Adjusted operating income (loss)


Natural Gas

Q3 2016 Q3 2015 Q3 2016 Q3 2015

Liquids

Line 2 hydrotest expenses, net of recoveries

Operating income (loss)




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


Adjusted gross margin

Natural Gas Q3 2016 Q3 2015

Operating revenues

Commodity costs



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 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.



Goodwill impairment

Interest expense, net


Asset impairment

Income tax expense


Net income (loss) attributable to noncontrolling interest





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



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


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

third quarter 2016 earnings presentation - enbridge/media/eepeeqmep...q3 2016 financial summary...

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