Second Quarter 2016 Earnings Presentation - Enbridge/media/EepEeqMep/Events/EEPEEQ/2016... · Second Quarter 2016 Earnings Presentation July 28, 2016 Enbridge Energy Partners, L.P.

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.

http://www.sec.gov/

http://www.sec.gov/

http://www.sec.gov/

http://www.sec.gov/

http://www.sec.gov/

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)


Less: Net income attributable to:

Adjusted net income attributable to general and limited partner ownership in EEP(1)

Noncontrolling interest


Interest expense, net(1)


2016 2015 Change

Adjusted segmented operating income (loss):

- Liquids (1)

- Natural Gas (1)

Adjusted operating income(1)


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)


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.


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.


20152016 Change


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)


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


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)


(1)

2016 2015


Power


Change

Operating and administrative expenses(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; 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.





Change2016 2015


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)


(1) Excludes the impact of: (a) non-cash, mark-to-market net gains and losses - see non-GAAP reconciliations.





Change2016 2015


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


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


(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)


Net income (loss) attributable to general and limited partner ownership

(unaudited; dollars 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 (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


Line 2 hydrotest expenses, net of recoveries

Operating income (loss)

Noncash derivative fair value losses



Natural Gas

Q2 2016 Q2 2015 Q2 2016 Q2 2015

Liquids


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


Adjusted gross margin

Natural Gas Q2 2016 Q2 2015

Operating revenues

Commodity costs



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.



Goodwill impairment

Interest expense, net


Asset impairment

Income tax expense (benefit)


Net income attributable to noncontrolling interest



Six months ended

June 30,

2016

Three months ended

2015 2015(unaudited; dollars in millions) 2016

Adjusted EBITDA June 30,


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



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)


Distributions in excess of equity earnings

Non-controlling interests


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.

Second Quarter 2016 Earnings Presentation - Enbridge/media/EepEeqMep/Events/EEPEEQ/2016... · Second Quarter 2016 Earnings Presentation July 28, 2016 Enbridge Energy Partners, L.P.

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