ENBRIDGE ENERGY PARTNERS LP - FORM 10-Q - November 1, 2017

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EX-32.2 - EXHIBIT 32.2 - ENBRIDGE ENERGY PARTNERS LPeep9302017-exhibit322.htm
EX-32.1 - EXHIBIT 32.1 - ENBRIDGE ENERGY PARTNERS LPeep9302017-exhibit321.htm
EX-31.2 - EXHIBIT 31.2 - ENBRIDGE ENERGY PARTNERS LPeep9302017-exhibit312.htm
EX-31.1 - EXHIBIT 31.1 - ENBRIDGE ENERGY PARTNERS LPeep9302017-exhibit311.htm
 

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
x
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2017
OR
o
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from            to           
Commission file number 1-10934
 
 
 
ENBRIDGE ENERGY PARTNERS, L.P.
(Exact Name of Registrant as Specified in Its Charter)
 
 
 
Delaware
 
39-1715850
(State or Other Jurisdiction of
Incorporation or Organization)
 
(I.R.S. Employer
Identification No.)

1100 Louisiana Street,
Suite 3300
Houston, Texas 77002
(Address of Principal Executive Offices) (Zip Code)
(713) 821-2000
(Registrant’s Telephone Number, Including Area Code)
Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.Yes x No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).Yes x No o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
 
Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)
 
Smaller reporting company o
Emerging growth company o
 
  
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).Yes o No x
The registrant had 326,517,110 Class A common units outstanding as of October 30, 2017.
 


ENBRIDGE ENERGY PARTNERS, L.P.

 TABLE OF CONTENTS
 
PART I — FINANCIAL INFORMATION
  
  
 
 
 
 
 
 
 
PART II — OTHER INFORMATION
  

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” “EEP” or the “Partnership” are intended to mean Enbridge Energy Partners, L.P. and its consolidated subsidiaries. We refer to our general partner, Enbridge Energy Company, Inc., as our “General Partner.” References to “Enbridge” refer collectively to Enbridge Inc., and its subsidiaries other than us. References to “Enbridge Management” refer to Enbridge Energy Management, L.L.C., the delegate of our General Partner that manages our business and affairs.

This Quarterly Report on Form 10-Q includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “consider,” “continue,” “could,” “estimate,” “evaluate,” “expect,” “explore,” “forecast,” “intend,” “may,” “opportunity,” “plan,” “position,” “projection,” “should,” “strategy,” “target,” “will” and similar words. Although we believe 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. Any forward-looking statement made by us in this Quarterly Report on Form 10-Q speaks only as of the date on which it is made, and we undertake no obligation to publicly update any forward-looking statement. Many of the factors that will determine these results are beyond our ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) the effectiveness of the various actions we have taken resulting from our strategic review process; (2) changes in the demand for the supply of, forecast data for, and price trends related to crude oil and liquid petroleum, including the rate of development of the Alberta Oil Sands; (3) our ability to successfully complete and finance expansion projects; (4) the effects of competition, in particular, by other pipeline systems; (5) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to whom we sell products; (6) hazards and operating risks that may not be covered fully by insurance, including those related to Line 6B and any additional fines and penalties and injunctive relief assessed in connection with the crude oil release on that line; (7) changes in or challenges to our tariff rates; (8) changes in laws or regulations to which we are 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 level or renewals of rights of way. Any statements regarding sponsor expectations or intentions are based on information communicated to us by Enbridge, but there can be no assurance that these expectations or intentions will not change in the future.

For additional factors that may affect results, see “Item-1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, and in any Quarterly Report on Form 10-Q filed thereafter, which are available to the public over the Internet at the U.S. Securities and Exchange Commission’s, or SEC’s, website (www.sec.gov) and at our website (www.enbridgepartners.com).

i

PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME
 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
(unaudited; in millions, except per unit amounts)
Operating revenues:
  

 
  

 
  

 
  

Transportation and other services
$
595.5

 
$
605.9

 
$
1,745.2

 
$
1,804.4

Transportation and other services – affiliate
20.9

 
28.7

 
72.4

 
81.2

  
616.4

 
634.6

 
1,817.6

 
1,885.6

Operating expenses:
  

 
  

 
  

 
  

Environmental costs, net of recoveries
1.2

 
(8.7
)
 
15.0

 
8.3

Operating and administrative
77.0

 
77.0

 
238.7

 
201.0

Operating and administrative – affiliate
85.6

 
75.0

 
235.3

 
227.0

Power
80.1

 
74.3

 
221.0

 
206.8

Depreciation and amortization
111.8

 
109.4

 
328.9

 
315.7

Gain on sale of assets
(5.5
)
 
—

 
(67.6
)
 
—

    Asset impairment
—

 
756.7

 
—

 
757.1

  
350.2

 
1,083.7

 
971.3

 
1,715.9

Operating income (loss)
266.2

 
(449.1
)
 
846.3

 
169.7

Interest expense, net
(104.1
)
 
(103.4
)
 
(305.8
)
 
(301.2
)
Allowance for equity used during construction
12.2

 
10.0

 
33.2

 
35.7

Other income
21.8

 
0.6

 
33.2

 
0.9

Income (loss) from continuing operations before income tax
196.1

 
(541.9
)
 
606.9

 
(94.9
)
Income tax benefit (expense)
(0.1
)
 
(1.6
)
 
0.4

 
(5.2
)
Income (loss) from continuing operations
196.0

 
(543.5
)
 
607.3

 
(100.1
)
Loss from discontinued operations, net of tax
—

 
(31.1
)
 
(56.8
)
 
(124.4
)
Net income (loss)
196.0

 
(574.6
)
 
550.5

 
(224.5
)
Less: Net income (loss) attributable to:
  

 
  

 
  

 
  

Noncontrolling interests
102.9

 
(191.9
)
 
261.8

 
(52.8
)
Series 1 preferred unit distributions
—

 
22.5

 
29.0

 
67.5

Accretion of discount on Series 1 preferred units
—

 
1.2

 
8.5

 
3.5

Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.
$
93.1

 
$
(406.4
)
 
$
251.2

 
$
(242.7
)
Net income (loss) allocable to common units and i-units:
  

 
  

 
  

 
  

Income (loss) from continuing operations
$
82.0

 
$
(432.7
)
 
$
254.1

 
$
(313.9
)
Income (loss) from discontinued operations
—

 
(19.9
)
 
(38.0
)
 
(86.9
)
Net income allocable to common units and i-units
$
82.0

 
$
(452.6
)
 
$
216.1

 
$
(400.8
)
Net income (loss) per common unit and i-unit (basic and diluted):
  

 
  

 
  

 
  

Income from continuing operations
$
0.19

 
$
(1.25
)
 
$
0.65

 
$
(0.91
)
Loss from discontinued operations
—

 
(0.06
)
 
(0.10
)
 
(0.25
)
Net income per common unit and i-unit
$
0.19

 
$
(1.31
)
 
$
0.55

 
$
(1.16
)
Weighted average common units and i-units outstanding (basic and diluted)
421.0

 
349.1

 
391.6

 
347.0

Distributions paid per limited partner unit
$
0.350

 
$
0.583

 
$
1.283

 
$
1.749







The accompanying notes are an integral part of these consolidated financial statements.

1

ENBRIDGE ENERGY PARTNERS, L.P. 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
(unaudited; in millions)
Net income (loss)
$
196.0

 
$
(574.6
)
 
$
550.5

 
$
(224.5
)
Other comprehensive income (loss), net of tax
  

 
  

 
  

 
  

Change in unrealized (gain) loss on cash flow hedges
(4.2
)
 
4.8

 
(24.5
)
 
(134.3
)
Reclassification to earnings of loss on cash flow hedges
9.8

 
9.9

 
30.5

 
29.7

Other comprehensive income (loss), net of tax
5.6

 
14.7

 
6.0

 
(104.6
)
Comprehensive income (loss)
201.6

 
(559.9
)
 
556.5

 
(329.1
)
Less:
  

 
  

 
  

 
  

Comprehensive income (loss) attributable to noncontrolling interests
102.9

 
(191.9
)
 
261.8

 
(52.8
)
Net income attributable to Series 1 preferred unit distributions
—

 
22.5

 
29.0

 
67.5

Net income attributable to accretion of discount on Series 1 preferred units
—

 
1.2

 
8.5

 
3.5

Comprehensive income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.
$
98.7

 
$
(391.7
)
 
$
257.2

 
$
(347.3
)

 

































The accompanying notes are an integral part of these consolidated financial statements.


2


ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
 
Nine months ended September 30,
  
2017
 
2016
 
 
 
 
  
(unaudited; in millions)
Series 1 Preferred units:
  

 
  

Beginning balance
$
1,191.5

 
$
1,186.8

Redemption of preferred units (Note 11)
(1,200.0
)
 
—

Net income
29.0

 
67.5

Distribution payable
(29.0
)
 
(67.5
)
Accretion of discount on preferred units
8.5

 
3.5

Ending balance
$
—

 
$
1,190.3

Class D units:
  

 
  

Beginning balance
$
2,517.6

 
$
2,517.6

Waiver of Class D units (Note 11)
(2,479.1
)
 
—

Net income
—

 
115.6

Distributions
(38.5
)
 
(115.6
)
Ending balance
$
—

 
$
2,517.6

Class E units:
  

 
  

Beginning balance
$
778.2

 
$
778.2

Net income
19.0

 
31.7

Distributions
(23.2
)
 
(31.7
)
Ending balance
$
774.0

 
$
778.2

Class A common units:
  

 
  

Net income
$
141.1

 
$
458.6

Issuance of Class A units (Note 11)
1,200.0

 
—

Distributions
(381.4
)
 
(458.6
)
Sale of noncontrolling interest in subsidiary
28.5

 
—

Other
0.7

 
—

Ending balance
$
988.9

 
$
—

Class B common units:
  

 
  

Net income
$
9.1

 
$
13.7

Sale of noncontrolling interest in subsidiary
0.9

 
—

Distributions
(10.0
)
 
(13.7
)
Ending balance
$
—

 
$
—

i-units:
  

 
  

Beginning balance
$
—

 
$
212.6

Net loss
(8.9
)
 
(212.6
)
Sale of noncontrolling interest in subsidiary
8.9

 
—

Ending balance
$
—

 
$
—

Class F units:
  

 
  

Issuance of Class F units (Note 11)
$
263.0

 
$
—

Net income
11.1

 
—

Distributions
(7.4
)
 
—

Ending balance
$
266.7

 
$
—





3

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL - (continued)
 
Nine months ended September 30,
  
2017
 
2016
 
 
 
 
  
(unaudited; in millions)
Incentive distribution units:
  

 
  

Beginning balance
$
495.2

 
$
495.0

Waiver of incentive distribution units (Note 11)
(489.9
)
 
—

Net income
—

 
15.7

Distributions
(5.3
)
 
(15.6
)
Ending balance
$
—

 
$
495.1

General Partner:
  

 
  

Beginning balance
$
(666.8
)
 
$
147.4

Net income (loss)
79.8

 
(665.4
)
Waiver of Class D units and incentive distribution units
2,969.0

 
—

Issuance of Class F units (Note 11)
(263.0
)
 
—

Contributions
92.1

 
—

Sale of Midcoast assets (Note 6)
(2,126.5
)
 
—

Distributions
(9.5
)
 
(12.9
)
Sale of noncontrolling interest in subsidiary
0.8

 
—

Ending balance
$
75.9

 
$
(530.9
)
Accumulated other comprehensive loss:
  

 
  

Beginning balance
$
(339.3
)
 
$
(370.0
)
Changes in fair value of derivative financial instruments reclassified to earnings
30.5

 
29.7

Changes in fair value of derivative financial instruments recognized in other comprehensive loss
(24.5
)
 
(134.3
)
Ending balance
$
(333.3
)
 
$
(474.6
)
Noncontrolling interests:
  

 
  

Beginning balance
$
3,846.1

 
$
3,944.5

Capital contributions
1,410.4

 
79.2

Sale of noncontrolling interest in subsidiary
411.0

 
—

Acquisition of noncontrolling interest in subsidiary
(360.3
)
 
—

Sale of Midcoast assets (Note 6)
(296.6
)
 
—

Net income
261.8

 
(52.8
)
Distributions to noncontrolling interests
(376.0
)
 
(125.2
)
Ending balance
$
4,896.4

 
$
3,845.7

Total partners’ capital at end of period
$
6,668.6

 
$
7,821.4

 











The accompanying notes are an integral part of these consolidated financial statements.


4

ENBRIDGE ENERGY PARTNERS, L.P. 
CONSOLIDATED STATEMENTS OF CASH FLOWS
 
Nine months ended September 30,
  
2017
 
2016
 
 
 
 
  
(unaudited; in millions)
Operating activities:
  

 
  

Net income from continuing operations
$
607.3

 
$
(100.1
)
Adjustments to reconcile net income to net cash provided by operating activities:
  

 
  

Depreciation and amortization
328.9

 
315.7

Derivative fair value net losses
1.2

 
10.4

Environmental costs, net of recoveries
14.5

 
6.3

Distributions from investment in joint venture
28.1

 
—

Equity earnings from investment in joint venture
(28.1
)
 
—

Gain on sale of assets
(67.6
)
 
—

Allowance for equity used during construction
(33.2
)
 
(35.7
)
Amortization of debt issuance and hedging costs
27.4

 
30.5

Asset impairment
—

 
757.1

Other
(0.1
)
 
7.8

Changes in operating assets and liabilities
(318.5
)
 
(170.8
)
Net cash provided by operating activities
559.9

 
821.2

Net cash (used in) provided by discontinued operations
(171.1
)
 
139.9

 
 
 
 
Investing activities:
  

 
  

Capital expenditures
(417.8
)
 
(838.3
)
Changes in restricted cash
13.6

 
8.2

Proceeds from the sale of assets
318.9

 
—

Proceeds from the sale of Midcoast assets
1,310.0

 
—

Investments in joint venture
(1,577.3
)
 
—

Distributions from investment in joint venture in excess of cumulative earnings
12.0

 
—

Other
(2.9
)
 
(2.3
)
Net cash used in investing activities
(343.5
)
 
(832.4
)
Net cash used in discontinued operations
(14.0
)
 
(17.2
)
 
 
 
 
Financing activities:
  

 
  

Redemption of Series 1 preferred units
(1,200.0
)
 
—

Payment of Series 1 preferred unit dividends
(357.3
)
 
—

Net proceeds from Class A unit issuances
1,224.5

 
—

Distributions to partners
(475.3
)
 
(598.6
)
Repayments to General Partner and affiliates
(1,706.0
)
 
—

Borrowings from General Partner and affiliates
1,500.0

 
—

Net (repayments) borrowings under credit facilities
(1,065.0
)
 
550.0

Net commercial paper borrowings (repayments)
685.9

 
(33.8
)
Acquisition of noncontrolling interest in subsidiary
(360.3
)
 
—

Sale of noncontrolling interest in subsidiary
450.1

 
—

Contributions from noncontrolling interests
1,390.3

 
62.4

Distributions to noncontrolling interests
(376.0
)
 
(57.2
)
Other
(0.3
)
 
(0.8
)
Net cash used in financing activities
(289.4
)
 
(78.0
)
Net cash (used in) provided by discontinued operations
229.0

 
(140.7
)
 
 
 
 
Net decrease in cash and cash equivalents
(29.1
)
 
(107.2
)
Cash disposed as part of the Midcoast sale
(51.3
)
 
—

Cash and cash equivalents at beginning of year – continuing operations
101.3

 
130.1

Cash and cash equivalents at beginning of year – discontinued operations
7.4

 
18.0

Cash and cash equivalents at end of period – continuing operations
28.3

 
40.9

Cash and cash equivalents at end of period – discontinued operations
$
—

 
$
—

 
The accompanying notes are an integral part of these consolidated financial statements.

5

ENBRIDGE ENERGY PARTNERS, L.P.
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
 
September 30,
2017
 
December 31,
2016
 
 
 
 
  
(unaudited; in millions,
except per unit amounts)
ASSETS
  

 
  

Current assets:
  

 
  

Cash and cash equivalents
$
28.3

 
$
101.3

Restricted cash
—

 
13.6

Receivables, trade and other
77.8

 
6.0

Due from General Partner and affiliates
79.2

 
88.4

Accrued receivables
96.7

 
18.8

Other current assets
36.9

 
34.3

Current assets related to discontinued operations
—

 
138.6

  
318.9

 
401.0

Property, plant and equipment, net
12,820.1

 
12,608.2

Equity investment in joint venture
1,565.3

 
—

Other assets, net
33.9

 
118.8

Assets held for sale
—

 
206.8

Non-current assets related to discontinued operations
—

 
4,775.3

Total Assets
$
14,738.2

 
$
18,110.1

LIABILITIES AND PARTNERS’ CAPITAL
  

 
  

Current liabilities:
  

 
  

Accounts payable and other
$
352.8

 
$
347.7

Due to General Partner and affiliates
55.4

 
175.2

Interest payable
109.5

 
90.1

Environmental liabilities
18.1

 
99.8

Property and other taxes payable
88.2

 
89.6

Current portion of long-term debt
399.8

 
—

Current liabilities related to discontinued operations
—

 
299.8

  
1,023.8

 
1,102.2

Long-term debt
6,291.1

 
7,065.9

Loans from General Partner and affiliate
544.0

 
750.0

Due to General Partner and affiliates
—

 
328.3

Other long-term liabilities
210.7

 
196.9

Non-current liabilities related to discontinued operations
—

 
844.3

  
8,069.6

 
10,287.6

Commitments and contingencies


 


Partners’ capital:
 
 
  

Series 1 preferred units (48,000,000 authorized and issued at December 31, 2016)
—

 
1,191.5

Class D units (66,100,000 authorized and issued at December 31, 2016)
—

 
2,517.6

Class E units (18,114,975 authorized and issued at September 30, 2017 and December 31, 2016, respectively)
774.0

 
778.2

Class A common units (326,517,110 and 262,208,428 outstanding at September 30, 2017 and December 31, 2016, respectively)
988.9

 
—

Class B common units (7,825,500 authorized and issued at September 30, 2017 and December 31, 2016, respectively)
—

 
—

i-units (87,569,475 and 81,857,168 authorized and issued at September 30, 2017 and December 31, 2016, respectively)
—

 
—

Class F units (1,000 authorized and issued at September 30, 2017)
266.7

 
—

Incentive distribution units (1,000 authorized and issued at December 31, 2016)
—

 
495.2

General Partner
75.9

 
(666.8
)
Accumulated other comprehensive loss
(333.3
)
 
(339.3
)
Total Enbridge Energy Partners, L.P. partners’ capital
1,772.2

 
3,976.4

Noncontrolling interests
4,896.4

 
3,543.2

Noncontrolling interests – discontinued operations
—

 
302.9

Total partners’ capital
6,668.6

 
7,822.5

Total Liabilities and Partners’ capital
$
14,738.2

 
$
18,110.1

The accompanying notes are an integral part of these consolidated financial statements.

6
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)



1. GENERAL
The terms “we”, “our”, “us” and “Enbridge Energy Partners” as used in this report refer collectively to Enbridge Energy Partners, L.P. and its subsidiaries unless the context suggests otherwise. Those terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge Energy Partners.
Nature of Operations
We, together with our consolidated subsidiaries, provide crude oil and liquid petroleum gathering, transportation and storage services. On June 28, 2017, we sold all of our ownership interest in our Midcoast gas gathering and processing business to our General Partner (the Midcoast sale). The sale of this ownership interest represents a strategic shift in our business and meets the criteria for classification as discontinued operations and as a result, the results of operations, cash flows and financial position of our natural gas business for the current and prior periods are reflected as discontinued operations. For further information refer to Note 6 - Dispositions, Asset Impairment and Discontinued Operations.
Basis of Presentation
The accompanying unaudited interim consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (U.S. GAAP), for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. They do not include all the information and notes required by U.S. GAAP for annual consolidated financial statements and should therefore be read in conjunction with our annual consolidated financial statements and notes presented in our Annual Report on Form 10-K for the year ended December 31, 2016. In the opinion of management, the interim consolidated financial statements contain all adjustments, consisting only of normal recurring adjustments, necessary to present fairly our financial position, results of operations and cash flows for the interim periods reported. These interim consolidated financial statements follow the same significant accounting policies as those included in our annual consolidated financial statements for the year ended December 31, 2016, except for the adoption of new standards.
Our operations and earnings for interim periods can be affected by seasonal fluctuations in the supply of and demand for crude oil, as well as other factors such as the timing and completion of our construction projects, the effect of environmental costs and related insurance recoveries on our Lakehead system, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value and may not be indicative of annual results.
2. CHANGES IN ACCOUNTING POLICIES
Adoption of New Standards
Clarifying the Definition of a Business in an Acquisition
Effective January 1, 2017, we early adopted ASU 2017-01 on a prospective basis. The new standard was issued with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (disposals) of assets or businesses. The adoption of the pronouncement did not have a material impact on our consolidated financial statements.
Accounting for Intra-Entity Asset Transfers
Effective January 1, 2017, we early adopted ASU 2016-16 on a modified retrospective basis. The new standard was issued with the intent of improving the accounting for the income tax consequences of intra-entity asset transfers other than inventory. Under the new guidance, an entity should recognize the income tax consequences of an intra-entity transfer of an asset, other than inventory, when the transfer occurs. The adoption of the pronouncement did not have a material impact on our consolidated financial statements.
Simplifying the Embedded Derivatives Analysis for Debt Instruments
Effective January 1, 2017, we adopted ASU 2016-06 on a modified retrospective basis. The new guidance simplifies the embedded derivative analysis for debt instruments containing contingent call or put options. The adoption of the pronouncement did not have a material impact on our consolidated financial statements.



7
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
2. CHANGES IN ACCOUNTING POLICIES – (continued)


Future Accounting Policy Changes
Improvements to Accounting for Hedging Activities
ASU 2017-12 was issued in August 2017 with the main objective of better aligning a company’s risk management activities and the resulting hedge accounting reflected in the financial statements. The amendments allow cash flow hedging of contractually specified components in financial and non-financial items and make fair value hedges of interest rate risks more effective in certain circumstances. Under the new guidance, hedge ineffectiveness is no longer required to be measured and hedging instruments’ fair value changes will be recorded in the same income statement line as the hedged item. The ASU also allows the initial quantitative hedge effectiveness assessment to be performed at any time before the end of the quarter in which the hedge is designated. After initial quantitative testing is performed, an ongoing qualitative effectiveness assessment is permitted. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted and is to be applied on a modified retrospective basis.
Accounting for Credit Losses
ASU 2016-13 was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. Current treatment uses the incurred loss methodology for recognizing credit losses that delays the recognition until it is probable a loss has been incurred. The amendment adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses, which the Financial Accounting Standards Board believes will result in more timely recognition of such losses. We are currently assessing the impact of the new standard on our consolidated financial statements. The accounting update is effective for annual and interim periods beginning on or after December 15, 2019.
Recognition of Leases
ASU 2016-02 was issued in February 2016 with the intent to increase transparency and comparability among organizations. It requires lessees of operating lease arrangements to recognize lease assets and lease liabilities on the statement of financial position and disclose additional key information about lease agreements. The accounting update also replaces the current definition of a lease and requires that an arrangement be recognized as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We are currently gathering a complete inventory of our lease contracts in order to assess the impact of the new standard on our consolidated financial statements. The accounting update is effective for fiscal years beginning after December 15, 2018 and is to be applied using a modified retrospective approach.
Revenues from Contracts with Customers
ASU 2014-09 was issued in 2014 with the intent of significantly enhancing consistency and comparability of revenue recognition practices across entities and industries. The new standard establishes a single, principles-based five-step model to be applied to all contracts with customers and introduces new and enhanced disclosure requirements. The standard is effective for fiscal years beginning after December 15, 2017. The new revenue standard permits either a full retrospective method of adoption with restatement of all prior periods presented, or a modified retrospective method with the cumulative effect of applying the new standard recognized as an adjustment to opening retained earnings in the period of adoption. We have decided to adopt the new revenue standard using the modified retrospective method.

We have reviewed a sample of our revenue contracts in order to evaluate the effect of the new standard on our revenue recognition practices. Based on our initial assessment, estimates of variable consideration which will be required under the new standard for certain contracts may result in changes to the pattern or timing of revenue recognition for those contracts. While we have not yet completed the assessment, our preliminary view is that we do not expect these changes to have a material impact on revenue or earnings (loss). We have also developed and tested processes to generate the disclosures required under the new standard.

8
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)


3. NET INCOME PER LIMITED PARTNER UNIT
We determined basic and diluted net income per limited partner unit as follows:
 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
  
(in millions, except per unit amounts)
Continuing operations:
  

 
  

 
  

 
  

Net income (loss)
$
196.0

 
$
(543.5
)
 
$
607.3

 
$
(100.1
)
Less: Net income (loss) attributable to:
  

 
  

 
  

 
 

Noncontrolling interest
102.9

 
(182.3
)
 
280.6

 
(16.9
)
Series 1 preferred unit distributions
—

 
22.5

 
29.0

 
67.5

Accretion of discount on Series 1 preferred units
—

 
1.2

 
8.5

 
3.5

Net income (loss) attributable to general and limited partner interests in Enbridge Energy Partners, L.P. – continuing operations
93.1

 
(384.9
)
 
289.2

 
(154.2
)
Distributions:
  

 
  

 
  

 
  

Incentive distributions(1)
(3.7
)
 
(5.3
)
 
(11.1
)
 
(15.7
)
Distributed earnings attributed to our General Partner
(3.2
)
 
(5.2
)
 
(9.6
)
 
(15.7
)
Distributed earnings attributed to Class D and Class E units(1)
(6.3
)
 
(49.1
)
 
(19.0
)
 
(147.3
)
Total distributed earnings to our General Partner, Class D, Class E and Class F units
(13.2
)
 
(59.6
)
 
(39.7
)
 
(178.7
)
Total distributed earnings attributed to our common units and i-units
(147.7
)
 
(204.1
)
 
(441.0
)
 
(608.7
)
Total distributed earnings
(160.9
)
 
(263.7
)
 
(480.7
)
 
(787.4
)
Overdistributed earnings
$
(67.8
)
 
$
(648.6
)
 
$
(191.5
)
 
$
(941.6
)
Discontinued operations:
  

 
  

 
  

 
  

Net loss
$
—

 
$
(31.1
)
 
$
(56.8
)
 
$
(124.4
)
Less: Net loss attributable to:
  

 
  

 
  

 
  

Noncontrolling interest
—

 
(9.6
)
 
(18.8
)
 
(35.9
)
Net loss attributable to general and limited partner interests in Enbridge Energy Partners, L.P. – discontinued operations
$
—

 
$
(21.5
)
 
$
(38.0
)
 
$
(88.5
)
Weighted average common units and i-units outstanding
421.0

 
349.1

 
391.6

 
347.0




9
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

3. NET INCOME PER LIMITED PARTNER UNIT  – (continued)


 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
(in millions, except per unit amounts)
Basic and diluted earnings per unit:
  

 
  

 
  

 
  

Distributed earnings per common unit and i-unit – continuing operations(2)
$
0.35

 
$
0.58

 
$
1.13

 
$
1.75

Overdistributed earnings per common unit and i-unit(3)
(0.16
)
 
(1.83
)
 
(0.48
)
 
(2.66
)
Net income (loss) per common unit and i-unit (basic and diluted) – continuing operations(4)
0.19

 
(1.25
)
 
0.65

 
(0.91
)
Net loss per common unit and i-unit (basic and diluted) – discontinued operations(4)
—

 
(0.06
)
 
(0.10
)
 
(0.25
)
Net income (loss) per common unit and i-unit (basic and diluted)
$
0.19

 
$
(1.31
)
 
$
0.55

 
$
(1.16
)
_____________________
(1)
For the three and nine months ended September 30, 2017, Class D units and incentive distribution units (IDUs) were not entitled to distributions as the wholly-owned subsidiary of our General Partner irrevocably waived its rights associated with the Class D units and IDUs; for the three and nine months ended September 30, 2017, incentive distributions were made to Class F units. For the three and nine months ended September 30, 2016, incentive distributions were made to IDUs and Class D units.
(2)
Represents the total distributed earnings to common units and i-units divided by the weighted average number of common units and i-units outstanding for the period.
(3)
Represents the common units’ and i-units’ share (98%) of distributions in excess of earnings divided by the weighted average number of common units and i-units outstanding for the period and overdistributed earnings allocated to the common units and i-units based on the distribution waterfall that is outlined in our partnership agreement.
(4)
For the three months ended September 30, 2017, 18,114,975 anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per share. For the nine months ended September 30, 2017 and the three and nine months ended September 30, 2016, 43,201,310 anti-dilutive Preferred units and 18,114,975 anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit. Effective April 27, 2017, a wholly-owned subsidiary of our General Partner irrevocably waived all of its rights associated with the Class D units, as such for the nine months ended September 30, 2017, 66,100,000 of Class D units were excluded from the if-converted method of calculating diluted earnings per unit. For the three and nine months ended September 30, 2016, 66,100,000 anti-dilutive Class D units were excluded from the if-converted method of calculating diluted earnings per unit.
Simplification of Incentive Distributions
On April 27, 2017, a wholly-owned subsidiary of our General Partner irrevocably waived all of its rights associated with its 66.1 million Class D units and its 1,000 incentive distribution units (IDUs) in exchange for the issuance of 1,000 Class F units. The irrevocable waiver is effective with respect to distributions declared with a record date after April 27, 2017. The Class F units are entitled to receive an incentive distribution for amounts distributed in excess of the Minimum Quarterly Distribution as described in the following table:

Distribution Targets
 
Portion of Quarterly
Distribution Per Unit
 
Percentage Distributed
to General Partner and
 Class F Units (1)
 
Percentage Distributed
to Limited Partners
Minimum Quarterly Distribution
 
Up to $0.295
 
2%
 
98%
First Target Distribution
 
> $0.295 to $0.35
 
15%
 
85%
Over First Target Distribution
 
> $0.35
 
25%
 
75%
_____________________
(1)
For distributions in excess of the Minimum Quarterly Distribution, this percentage includes both the General Partner’s distributions of 2% and the distribution to the Class F Units.




10
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)


4. SEGMENT INFORMATION

 
Three months ended September 30, 2017
  
Liquids
 
Natural Gas
 
Other
 
Consolidated(1)
 
 
 
 
 
 
 
 
  
(in millions)
Operating revenues:(2)
  

 
  

 
  

 
  

Transportation and other services
$
616.4

 
$
—

 
$
—

 
$
616.4

  
616.4

 
—

 
—

 
616.4

Operating expenses:
  

 
  

 
  

 
  

Environmental costs, net of recoveries
1.2

 
—

 
—

 
1.2

Operating and administrative
160.9

 
—

 
1.7

 
162.6

Power
80.1

 
—

 
—

 
80.1

Depreciation and amortization
111.8

 
—

 
—

 
111.8

Gain on sale of assets
(5.5
)
 
—

 
—

 
(5.5
)
 
348.5

 
—

 
1.7

 
350.2

Operating income (loss)
267.9

 
—

 
(1.7
)
 
266.2

Interest expense, net
 
 
 
 
 
 
(104.1
)
Allowance for equity used during construction
 
 
 
 
 
 
12.2

Other income
21.7

(3) 
—

 
0.1

 
21.8

Income before income taxes
 
 
 
 
 
 
196.1

Income tax expense
 
 
 
 
 
 
(0.1
)
Net income
 
 
 
 
 
 
$
196.0

____________________
(1)
Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction and income taxes are included in the consolidated total.
(2)
There were no intersegment revenues for the three months ended September 30, 2017.
(3)
Other income includes our equity income from our investment in the Bakken Pipeline System.


11
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

4. SEGMENT INFORMATION  – (continued)


 
Three months ended September 30, 2016
  
Liquids
 
Natural Gas(1)
 
Other
 
Consolidated(2)
 
 
 
 
 
 
 
 
  
(in millions)
Operating revenues:(3)
  

 
  

 
  

 
  

Transportation and other services
$
634.6

 
$
—

 
$
—

 
$
634.6

  
634.6

 
—

 
—

 
634.6

Operating expenses:
  

 
  

 
  

 
  

Environmental costs, net of recoveries
(8.7
)
 
—

 
—

 
(8.7
)
Operating and administrative
149.7

 
—

 
2.3

 
152.0

Power
74.3

 
—

 
—

 
74.3

Depreciation and amortization
109.4

 
—

 
—

 
109.4

Asset impairment
756.7

 
—

 
—

 
756.7

  
1,081.4

 
—

 
2.3

 
1,083.7

Operating loss
(446.8
)
 
—

 
(2.3
)
 
(449.1
)
Interest expense, net
 
 
 
 
 
 
(103.4
)
Allowance for equity used during construction
 
 
 
 
 
 
10.0

Other income
 
 
 
 
 
 
0.6

Loss from continuing operations before income taxes
 
 
 
 
 
 
(541.9
)
Income tax expense
 
 
 
 
 
 
(1.6
)
Loss from continuing operations
 
 
 
 
 
 
(543.5
)
Loss from discontinued operations
—

 
(20.6
)
 
(10.5
)
 
(31.1
)
Net loss
 
 
 
 
 
 
$
(574.6
)
_____________________
(1)
The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 - Dispositions, Asset Impairment and Discontinued Operations.
(2)
Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, other income and income taxes are included in the consolidated total.
(3)
There were no intersegment revenues for the three months ended September 30, 2016.

12
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

4. SEGMENT INFORMATION  – (continued)


 
Nine months ended September 30, 2017
  
Liquids
 
Natural Gas(1)
 
Other
 
Consolidated(2)
 
 
 
 
 
 
 
 
  
(in millions)
Operating revenues:(3)
  

 
  

 
  

 
  

Transportation and other services
$
1,817.6

 
$
—

 
$
—

 
$
1,817.6

  
1,817.6

 
—

 
—

 
1,817.6

Operating expenses:
  

 
  

 
  

 
  

Environmental costs, net of recoveries
15.0

 
—

 
—

 
15.0

Operating and administrative
464.9

 
—

 
9.1

 
474.0

Power
221.0

 
—

 
—

 
221.0

Depreciation and amortization
328.9

 
—

 
—

 
328.9

Gain on sale of assets
(67.6
)
 
—

 
—

 
(67.6
)
  
962.2

 
—

 
9.1

 
971.3

Operating income (loss)
855.4

 
—

 
(9.1
)
 
846.3

Interest expense, net
 
 
 
 
 
 
(305.8
)
Allowance for equity used during construction
 
 
 
 
 
 
33.2

Other income
28.1

(4) 
—

 
5.1

 
33.2

Income from continuing operations before income tax benefit
 
 
 
 
 
 
606.9

Income tax benefit
 
 
 
 
 
 
0.4

Income from continuing operations
 
 
 
 
 
 
607.3

Loss from discontinued operations
—

 
(51.1
)
 
(5.7
)
 
(56.8
)
Net income
 
 
 
 
 
 
$
550.5

_____________________
(1)
The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 - Dispositions, Asset Impairment and Discontinued Operations.
(2)
Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction and income taxes are included in the consolidated total.
(3)
There were no intersegment revenues for the nine months ended September 30, 2017.
(4)
Other income includes our equity income from our investment in the Bakken Pipeline System.

13
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

4. SEGMENT INFORMATION  – (continued)


 
Nine months ended September 30, 2016
  
Liquids
 
Natural Gas(1)
 
Other
 
Consolidated(2)
 
 
 
 
 
 
 
 
  
(in millions)
Operating revenues:(3)
  

 
  

 
  

 
  

Transportation and other services
$
1,885.6

 
$
—

 
$
—

 
$
1,885.6

  
1,885.6

 
—

 
—

 
1,885.6

Operating expenses:
  

 
  

 
  

 
  

Environmental costs, net of recoveries
8.3

 
—

 
—

 
8.3

Operating and administrative
418.6

 
—

 
9.4

 
428.0

Power
206.8

 
—

 
—

 
206.8

Depreciation and amortization
315.7

 
—

 
—

 
315.7

Asset impairment
757.1

 
—

 
—

 
757.1

  
1,706.5

 
—

 
9.4

 
1,715.9

Operating income (loss)
179.1

 
—

 
(9.4
)
 
169.7

Interest expense, net
 
 
 
 
 
 
(301.2
)
Allowance for equity used during construction
 
 
 
 
 
 
35.7

Other income
 
 
 
 
 
 
0.9

Loss from continuing operations before income taxes
 
 
 
 
 
 
(94.9
)
Income tax expense
 
 
 
 
 
 
(5.2
)
Loss from continuing operations
 
 
 
 
 
 
(100.1
)
Loss from discontinued operations
—

 
(96.9
)
 
(27.5
)
 
(124.4
)
Net loss
 
 
 
 
 
 
$
(224.5
)
_____________________
(1)
The operating results of our Natural Gas segment are included in discontinued operations as a result of the Midcoast sale to our General Partner. For further information refer to Note 6 - Dispositions, Asset Impairment and Discontinued Operations.
(2)
Certain costs that are not allocated to individual segments, including Other, interest expense, allowance for equity used during construction, other income and income taxes are included in the consolidated total.
(3)
There were no intersegment revenues for the nine months ended September 30, 2016.

Total Assets
 
September 30,
2017
 
December 31, 2016(1)
Liquids
 
$
14,721.5

 
$
13,030.5

Natural Gas
 
—

 
—

Other
 
16.7

 
165.6

Total
 
$
14,738.2

 
$
13,196.1

_____________________
(1)
Comparative information excludes assets from discontinued operations. See Note 6 - Dispositions, Asset Impairment and Discontinued Operations.


14
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)


5. REGULATORY MATTERS
Regulatory Accounting
Due to over or under revenue recovery adjustments made in accordance with the Federal Energy Regulatory Commission (FERC), authoritative guidance and our cost-of-service recovery model, we recognize assets and liabilities for regulatory purposes. The assets and liabilities that we recognize for regulatory purposes are recorded on a net basis in “Other current assets” or “Accounts payable and other,” respectively, on our consolidated statements of financial position. These regulatory assets and liabilities are amortized on a straight-line basis over a one-year recovery period. Our over and under recovery revenue adjustments and net regulatory asset amortization for the three and nine months ended September 30, 2017 and 2016 are as follows:
 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
(in millions)
Net regulatory asset (liability) balance at beginning of period
$
(23.7
)
 
$
29.3

 
$
11.9

 
$
29.9

Current period under recovery revenue adjustments
28.8

 
6.4

 
1.8

 
20.0

Amortization of prior year regulatory asset
(1.6
)
 
(7.9
)
 
(10.2
)
 
(22.1
)
Net regulatory asset balance at end of period
$
3.5

 
$
27.8

 
$
3.5

 
$
27.8


6. DISPOSITIONS, ASSET IMPAIRMENT AND DISCONTINUED OPERATIONS
Dispositions
For the nine months ended 2017, we sold unnecessary pipe related to the Sandpiper project for cash proceeds of approximately $103.0 million. A gain on disposal of $57.0 million before tax was included in “Gain on sale of assets” on our consolidated statements of income. These assets were part of our Liquids segment.
On March 1, 2017, we completed the sale of the Ozark Pipeline system to a subsidiary of MPLX LP for cash proceeds of approximately $219.6 million, including reimbursement costs. A gain on disposal of $10.6 million before tax was included in “Gain on sale of assets” on our consolidated statements of income. These assets were part of our Liquids segment.
Asset Impairment
During September 2016, we announced that we applied for the withdrawal of regulatory applications pending with the Minnesota Public Utilities Commission (MNPUC), for the Sandpiper Project which was included in our Liquids segment. In connection with this announcement and other factors, we evaluated the project for impairment. As a result of the analysis, we recognized an impairment loss of $756.7 million for the three months ended September 30, 2016, which was included in "Asset impairment" on our consolidated statements of income. Of that amount, $267.4 million was attributable to noncontrolling interests (NCI). The estimated remaining fair value of $54.5 million of the Sandpiper Project was based on the estimated price that would be received to sell unused pipe, land and other related equipment in its current condition, considering the market condition for the assets as of September 2016. The estimated fair value, excluding $2.6 million in land, was reclassified into "Other assets, net" and have been predominately sold as of the third quarter of 2017.
Discontinued Operations
Sale of Natural Gas Business
On June 28, 2017, we completed the sale of all of our ownership interest in our Midcoast gas gathering and processing business to our General Partner for $2.26 billion, which included cash consideration of $1.31 billion and outstanding indebtedness at Midcoast Energy Partners, L.P. (MEP) of $953.0 million. This sale included our 48.4% limited partnership interest in Midcoast Operating, L.P., our 51.9% limited partnership interest in MEP, and our 100% interest in Midcoast Holdings, L.L.C., MEP’s general partner. We recorded no gain or loss on the sale as this transaction was between entities under common control of Enbridge. The carrying value of the net assets sold was $4.29 billion. As a result of the transaction, partners’ capital decreased by $2.13 billion, all of which was allocated to the General Partner’s capital account. NCI in MEP of $296.6 million was eliminated.

15
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
6. DISPOSITIONS, ASSET IMPAIRMENT AND DISCONTINUED OPERATIONS  – (continued)

The following table presents the operating results from discontinued operations of our Midcoast gas gathering and processing business, which have been segregated from our continuing operations in our consolidated statements of income:
 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
Operating revenues:
  

 
  

 
  

 
  

Commodity sales
$
—

 
$
440.7

 
$
1,085.0

 
$
1,197.9

Commodity sales – affiliate
—

 
1.3

 
9.4

 
7.9

Transportation and other services
—

 
44.0

 
66.7

 
139.7

  
—

 
486.0

 
1,161.1

 
1,345.5

Operating expenses:
  

 
  

 
  

 
  

Commodity costs
—

 
396.1

 
968.2

 
1,082.0

Commodity costs – affiliate
—

 
7.9

 
42.1

 
29.1

Operating and administrative
—

 
36.6

 
64.7

 
111.4

Operating and administrative – affiliate
—

 
35.8

 
68.7

 
112.6

Depreciation and amortization
—

 
39.2

 
74.5

 
118.7

Asset impairment
—

 
—

 
—

 
10.6

  
—

 
515.6

 
1,218.2

 
1,464.4

Operating loss
—

 
(29.6
)
 
(57.1
)
 
(118.9
)
Interest expense, net
—

 
(9.0
)
 
(17.4
)
 
(25.5
)
Other income
—

 
8.1

 
18.6

 
22.0

Loss before income taxes
—

 
(30.5
)
 
(55.9
)
 
(122.4
)
Income tax expense
—

 
(0.6
)
 
(0.9
)
 
(2.0
)
Net loss from discontinued operations
$
—

 
$
(31.1
)
 
$
(56.8
)
 
$
(124.4
)

The following table presents the major classes of assets and liabilities for discontinued operations of our Midcoast gas gathering and processing business as presented in the consolidated statements of financial position:
 
December 31,
2016
Current assets related to discontinued operations:
  

Cash and cash equivalents
$
7.4

Restricted cash
11.0

Receivables, trade and other, net of allowance for doubtful accounts
8.5

Due from General Partner and affiliates
2.1

Accrued receivables
20.8

Inventory
28.1

Other current assets
60.7

  
$
138.6

Non-current assets related to discontinued operations:
  

Property, plant and equipment, net
$
4,114.5

Equity investment in joint venture
360.7

Intangible assets, net
251.8

Other assets, net
48.3

  
$
4,775.3


16
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
6. DISPOSITIONS, ASSET IMPAIRMENT AND DISCONTINUED OPERATIONS  – (continued)

 
December 31,
2016
Current liabilities related to discontinued operations:
  

Accounts payable and other
$
66.9

Due to General Partner and affiliates
38.8

Environmental liabilities
0.1

Accrued purchases
171.8

Property and other taxes payable
17.2

Interest payable
5.0

  
$
299.8

Non-current liabilities related to discontinued operations:
  

Long-term debt
$
818.5

Other long-term liabilities
25.8

  
$
844.3


7. VARIABLE INTEREST ENTITIES
Enbridge Holdings (DakTex) L.L.C.
On April 27, 2017, we finalized the joint funding arrangement with our General Partner with respect to our equity investment in the Bakken Pipeline System, held through our investment subsidiary, Enbridge Holdings (DakTex) L.L.C. (DakTex). DakTex is now owned 75% by our General Partner and 25% by us. DakTex owns a 75% equity interest in MarEn Bakken Company LLC (MarEn). For more information regarding our equity investment, refer to Note 8 - Equity Investment in Joint Venture.
DakTex is considered a variable interest entity consolidated by us. We have authority as managing member to exclusively manage the business and affairs of DakTex, subject to certain protective voting rights and are subject to removal as managing member only upon certain fundamental changes. We are the primary beneficiary of Daktex because (i) as the managing partner we have the power to direct the activities of DakTex that most significantly impact its economic performance; and (ii) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to DakTex.
DakTex does not have any liabilities. Its sole asset is its investment in MarEn. At September 30, 2017, the carrying amount of DakTex’s investment in MarEn was $1,546.6 million.

8. EQUITY INVESTMENT IN JOINT VENTURE
The following table presents our equity investment in a joint venture and ownership interest in MarEn.
 
Ownership
Interest
 
September 30,
2017
 
December 31,
2016
MarEn Bakken Company LLC
75.0%
 
$1,565.3
 
$—
On February 15, 2017, our joint venture with Marathon Petroleum Corporation (MPC), MarEn, closed its acquisition of an interest in the Bakken Pipeline System with Bakken Holdings Company LLC, an affiliate of Energy Transfer Partners, L.P. and Sunoco Logistics Partners L.P., to acquire a 49% equity interest in Bakken Pipeline Investments LLC (BPI), which owns 75% of the Bakken Pipeline System. Under this arrangement, we and MPC indirectly hold 75% and 25%, respectively, of MarEn’s 49% interest in BPI. The purchase price of our effective 27.6% interest in the Bakken Pipeline System was $1.5 billion.
The Bakken Pipeline System was placed into service on June 1, 2017, which consists of the Dakota Access Pipeline (DAPL) and the Energy Transfer Crude Oil Pipeline (ETCOP). It connects the Bakken formation in North Dakota to markets in eastern Petroleum Administration for Defense Districts (PADD II) and the United States Gulf Coast. For further details regarding our funding arrangement, refer to Note 14 - Related Party Transactions.

17
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)


We account for our investment in MarEn under the equity method of accounting. For the three and nine months ended September 30, 2017, we recognized $21.7 million and $28.1 million respectively in “Other income” in our consolidated statements of income representing our equity earnings for this investment, net of amortization of the excess of the purchase price over the underlying net book value (basis difference).
Our equity investment includes basis difference of the investees’ assets at the purchase date, which is comprised of $14.4 million in goodwill and $931.4 million in amortizable assets included within the Liquids segment. We amortized $9.9 million and $12.8 million respectively for the three and nine months ended September 30, 2017, which was recorded as a reduction to equity earnings.

9. DEBT
Credit Facilities
 
Maturity
Dates
 
Total Facilities
 
Draws(1)
 
Available
 
 
 
 
 
 
 
 
  
(in millions)
Enbridge Energy Partners, L.P.
2019 – 2020
 
$2,625.0
 
$1,345.8
 
$1,279.2
_____________________
(1)
Includes facility draws, letters of credit and commercial paper issuances that are back-stopped by the credit facility and excludes the our credit agreement with EUS (the EUS 364-day Credit Facility.)
In addition to the committed credit facilities noted in the above table, we also have $175.0 million available under a uncommitted letters of credit arrangement, of which $86.3 million and $70.9 million were unutilized as of September 30, 2017 and December 31, 2016, respectively.
Under our multi-year senior unsecured revolving credit facility and our 364-day revolving credit agreement (the Credit Facilities), we had net repayments of approximately $1.0 billion as of September 30, 2017, which includes gross borrowings of $8.8 billion and gross repayments of $9.8 billion.
Under our commercial paper program, we had net borrowings of approximately $0.7 billion as of September 30, 2017, which includes gross borrowings of $8.9 billion and gross repayments of $8.2 billion.
Under our credit agreement with EUS, an affiliate of Enbridge and the owner of our General Partner (the EUS 364-day Credit Facility), we had net repayments of approximately $0.2 billion as of September 30, 2017, which includes gross borrowings of $0.6 billion and gross repayments of $0.8 billion.
As of September 30, 2017 and December 31, 2016, respectively, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $1,280.5 million and $1,657.6 million are supported by the availability of long-term committed credit facilities and therefore have been classified as long-term debt.
As of September 30, 2017, we had approximately $1,485.2 million of unutilized commitments under the terms of our Credit Facilities and the EUS 364-day Credit Facility.
On October 2, 2017, we extended the maturity date attributable to our multi-year senior unsecured revolving credit facility. The maturity date was extended to September 26, 2022; however $185 million of the commitment will expire on September 26, 2020 and $175 million will expire on the original maturity date of September 26, 2018.
On July 25, 2017. we entered into an agreement with EUS whereby the termination date was extended to July 24, 2017, For further information, refer to Note 14 - Related Party Transactions.
On June 30, 2017, we extended our 364-day revolving credit facility termination date. The termination date was extended to June 29, 2018 , which has a term out option that could extend maturity of outstanding borrowings to June 28, 2019 and capacity remains at $625 million. The 364-day Credit Facility is through a syndicate of third party lenders.
On June 5, 2017, we entered into amendments with the lenders of each of our Credit Facilities and the EUS 364-day Credit Facility. These agreements eliminated certain covenants related to MEP and its subsidiaries and were effective June 28, 2017.

18
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
9. DEBT – (continued)


On April 27, 2017, our Board of Directors finalized the joint funding arrangement with our General Partner with respect to our investment in the Bakken Pipeline System, held through our subsidiary, DakTex. As part of the transaction, DakTex distributed approximately $1.14 billion to us. We used these distribution proceeds plus additional borrowings of $0.4 billion from our existing EUS 364-day Credit Facility to repay the $1.5 billion outstanding under our unsecured revolving 364-day credit agreement with EUS (the EUS Credit Agreement). We terminated the EUS Credit Agreement subsequent to the repayment. For further information on distribution from our General Partner, refer to Note 14 - Related Party Transactions.
We have the ability and intent to refinance all of our commercial paper obligations on a long-term basis through borrowings under our Credit Facilities. Accordingly, such amounts have been classified as “Long-term debt” in our accompanying consolidated statements of financial position.
Debt Covenants
We and our consolidated subsidiaries were in compliance with the terms of our financial covenants under our consolidated debt agreements as at September 30, 2017.
Fair Value of Debt Obligations
The carrying amounts of our outstanding commercial paper, borrowings under our Credit Facilities, and the EUS 364-day Credit Facility approximate their fair values at September 30, 2017 and December 31, 2016, respectively, due to the short-term nature and frequent repricing of the amounts outstanding under these obligations. The fair value of our outstanding commercial paper and borrowings under our Credit Facilities and the EUS 364-day Credit Facility are included with our long-term debt obligations above since we have the ability and the intent to refinance the amounts outstanding on a long-term basis.
The approximate fair value of our fixed-rate debt obligations was $6.2 billion and $6.5 billion at September 30, 2017 and December 31, 2016, respectively. We determined the approximate fair values using a standard methodology that incorporates pricing points that are obtained from independent, third-party investment dealers who actively make markets in our debt securities. We use these pricing points to calculate the present value of the principal obligation to be repaid at maturity and all future interest payment obligations for any debt outstanding. The fair value of our long-term debt obligations is categorized as Level 2 within the fair value hierarchy.

10. NONCONTROLLING INTERESTS
 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
(in millions)
Eastern Access Interests
$
37.6

 
$
48.3

 
$
113.9

 
$
153.0

U.S. Mainline Expansion Interests
39.1

 
39.0

 
108.3

 
99.7

North Dakota Pipeline Company Interests
1.8

 
(269.6
)
 
18.6

 
(269.6
)
Line 3 Replacement Interests
8.1

 
—

 
18.7

 
—

Enbridge Holdings (DakTex) L.L.C. Interests
16.3

 
—

 
21.1

 
—

Midcoast Energy Partners, L.P. – Discontinued Operations
—

 
(9.6
)
 
(18.8
)
 
(35.9
)
Total
$
102.9

 
$
(191.9
)
 
$
261.8

 
$
(52.8
)
On June 28, 2017, we completed the Midcoast sale to our General Partner, reducing our noncontrolling interest in MEP to nil upon the closing of the sale. For further details refer to Note 6 - Dispositions, Asset Impairment and Discontinued Operations
On April 27, 2017, we finalized the previously announced joint funding arrangement with our General Partner for our investment in the Bakken Pipeline System. Our equity investment in MarEn is held by our consolidated subsidiary, DakTex. Under the terms of the agreement, our General Partner contributed approximately $1.14 billion in exchange for Class A units in DakTex to obtain its 75% ownership interest while we retain the remaining 25%. NCI represent our General Partner’s 75% interest. For further details refer to Note 14 - Related Party Transactions.

19
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)


On January 26, 2017, we entered into a joint funding arrangement with our General Partner for the U.S. Line 3 Replacement Program (U.S. L3R Program). Under the term of the arrangement, our General Partner will fund 99% and we will fund 1% of the capital costs of the U.S. L3R Program. The carrying amount of our 99% interest in the project at the transaction date was $411.0 million and was recorded as an increase to noncontrolling interest. The $39.1 million difference between the cash received and the carrying amount was recorded as an increase to the capital accounts of our common units, i-units, and General Partner interest on a pro-rated basis. For further details, refer to Note 14 - Related Party Transactions.
On January 26, 2017, we exercised our option under the Eastern Access Project joint funding arrangement to acquire an additional 15% interest in the Eastern Access Project, at its book value of approximately $360 million, which is now in service. This transaction reduced noncontrolling interest by approximately $360 million. We and our General Partner own 40% and 60% of the partnership interest in Series EA of Enbridge Energy, Limited Partnership (OLP), which we refer to as the EA interest, respectively. For further details, refer to Note 14 - Related Party Transactions.


20
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)


11. PARTNERS' CAPITAL
Redemption of Series 1 Preferred Units
On April 27, 2017, we redeemed all of our outstanding Series 1 Preferred Units held by our General Partner at face value of $1.2 billion in cash. The remaining unamortized beneficial conversion feature discount of $8.5 million was recorded against the capital balance of the General Partner. Additionally, we repaid $357.3 million in deferred distributions on the Series 1 Preferred Units owed to our General Partner upon the closing of the Midcoast sale.
Issuance of Class A Units
On April 27, 2017, we funded the redemption of the Series 1 Preferred Units through the issuance of 64.3 million Class A common units to our General Partner at a price of $18.66 per Class A common unit. The Class A common units were recognized on April 27, 2017, at fair value. The fair value of the Class A common units was $18.57 per unit, the market closing price on April 27, 2017, resulting in a $1.2 billion increase to the Class A unit capital account.
Simplification of Incentive Distributions
On April 27, 2017, a wholly-owned subsidiary of our General Partner irrevocably waived all of its rights associated with its 66.1 million Class D units and 1,000 IDUs, in exchange for the issuance of 1,000 Class F units. The waiving of the Class D units and IDUs by a wholly-owned subsidiary of our General Partner represents an extinguishment, resulting in a de-recognition of the Class D units and IDUs at their carrying value. The Class F units were recorded at their fair value of $263.0 million and the difference between the fair value of the Class F units and the de-recognized Class D units and IDUs were recorded as an increase of $2.7 billion to our General Partner’s capital account. We determined the fair value of the Class F units using an income approach on the basis of discounted cash flows from expected quarterly distributions. The Class F units are entitled to (i) 13% of all distributions of available cash in excess of $0.295 per unit, but less than or equal to $0.35 per unit, and (ii) 23% of all distributions of available cash in excess of $0.35 per unit.
Curing
Our limited partnership agreement does not permit capital deficits to accumulate in the capital accounts of any limited partner and thus requires that such capital account deficits be “cured” by additional allocations from the positive capital accounts of the common units, i-units, and our General Partner, generally on a pro-rated basis. For the nine months ended September 30, 2017, the carrying amounts for the capital accounts of the Class B common units were reduced below zero due to distributions to limited partners in excess of earnings and were subsequently cured. Class A units and i-units had positive capital balances and therefore, as outlined in the partnership agreement, we allocated earnings of $75.3 million to our General Partner to recover previous curing allocations made by the General Partner.
12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES
As a result of the Midcoast sale, our net income and cash flows are no longer subject to volatility stemming from fluctuation in the prices of natural gas, NGLs, condensates and fractionation margins.
Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of crude oil. Our interest rate risk exposure results from changes in interest rates on our variable rate debt. Our exposure to commodity price risk exists within our Liquids segment. We use derivative financial instruments, such as futures, forwards, swaps, options and other financial instruments with similar characteristics, to manage the risks associated with market fluctuations in interest rates and commodity prices, as well as to reduce volatility in our cash flows. Based on our risk management policies, all of our derivative financial instruments, including those that are not designated for hedge accounting treatment, are employed in connection with an underlying asset, liability or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices. We have hedged a portion of our exposure to the variability in future cash flows associated with the risks discussed above in future periods in accordance with our risk management policies. Our derivative instruments that are designated for hedge accounting under authoritative guidance are classified as cash flow hedges.





21
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)


Derivative Positions
Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:
 
September 30,
2017
 
December 31,
2016
 
 
 
 
  
(in millions)
Other current assets
$
0.1

 
$
—

Accounts payable and other
(162.8
)
 
(145.4
)
Other long-term liabilities
(22.9
)
 
(21.3
)
  
$
(185.6
)
 
$
(166.7
)
The changes in the assets and liabilities associated with our derivatives are primarily attributable to the effects of new derivative transactions we have entered at prevailing market prices, settlement of maturing derivatives and the change in forward market prices of our remaining hedges. Our portfolio of derivative financial instruments is largely comprised of interest rate contracts and crude oil sales contracts.
The table below summarizes our derivative balances by counterparty credit quality (any negative amounts represent our net obligations to pay the counterparty).
 
September 30,
2017
 
December 31,
2016
 
 
 
 
  
(in millions)
Counterparty Credit Quality(1)
  

 
  

AA
$
(83.8
)
 
$
(79.2
)
A
(65.1
)
 
(58.4
)
Lower than A
(36.7
)
 
(29.1
)
  
$
(185.6
)
 
$
(166.7
)
_____________________
(1)
As determined by nationally-recognized statistical ratings organizations.
As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices and interest rates, our outstanding financial exposure to third parties has decreased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc. (ISDA®), financial contracts, we have the right to require collateral from our counterparties. We include any cash collateral received or posted in the balances listed above. At September 30, 2017 and December 31, 2016, we did not have any cash collateral on our asset exposures. Cash collateral is classified as “Restricted cash” in our consolidated statements of financial position.
We provided letters of credit totaling $152.6 million and $119.5 million relating to our liability exposures pursuant to the margin thresholds in effect at September 30, 2017 and December 31, 2016, respectively, under our ISDA® agreements. The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate and require immediate settlement of all future amounts due.

22
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)


The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.
In the event that our credit ratings were to decline below the lowest level of investment grade, as determined by Standard & Poor’s and Moody’s, we would be required to provide additional amounts under our existing letters of credit to meet the requirements of our ISDA® agreements. For example, if our credit ratings had been below the lowest level of investment grade at September 30, 2017, we would have been required to provide additional letters of credit in the amount of $34.1 million related to our positions.
At September 30, 2017 and December 31, 2016, we had credit concentrations in the following industry sectors, as presented below:
 
September 30,
2017
 
December 31,
2016
 
 
 
 
  
(in millions)
United States financial institutions and investment banking entities
$
(132.4
)
 
$
(121.7
)
Non-United States financial institutions
(53.2
)
 
(45.0
)
  
$
(185.6
)
 
$
(166.7
)
Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter, or OTC, derivatives is directly with our counterparty and continues until the maturity or termination of the contracts.


23
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)


Effect of Derivative Instruments on the Consolidated Statements of Financial Position
 
 
 
Asset Derivatives
 
Liability Derivatives
  
 
 
Fair Value at
 
Fair Value at
  
Financial Position
Location
 
September 30,
2017
 
December 31,
2016
 
September 30,
2017
 
December 31,
2016
 
 
 
 
 
 
 
 
 
 
  
  
 
(in millions)
Derivatives designated as hedging instruments:(1)
  
 
  

 
  

 
  

 
  

Interest rate contracts
Accounts payable and other
 
$
—

 
$
—

 
$
(162.2
)
 
$
(144.0
)
Interest rate contracts
Other long-term liabilities
 
—

 
—

 
(22.8
)
 
(21.1
)
  
 
 
—

 
—

 
(185.0
)
 
(165.1
)
Derivatives not designated as hedging instruments:
  
 
  

 
  

 
  

 
  

Commodity contracts
Other current assets
 
0.1

 
—

 
—

 
—

Commodity contracts
Accounts payable and other
 
—

 
—

 
(0.6
)
 
(1.4
)
Commodity contracts
Other long-term liabilities
 
—

 
—

 
(0.1
)
 
(0.2
)
  
 
 
0.1

 
—

 
(0.7
)
 
(1.6
)
Total derivative instruments
 
$
0.1

 
$
—

 
$
(185.7
)
 
$
(166.7
)
_____________________
(1)
Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in accumulated other comprehensive income (AOCI).
Accumulated Other Comprehensive Income
We record the change in fair value of our highly effective cash flow hedges in AOCI until the derivative financial instruments are settled, at which time they are reclassified to earnings. As of September 30, 2017 and December 31, 2016, we included in AOCI unrecognized losses of approximately $200.2 million and $223.3 million, respectively, associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated, settled, or terminated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings.
No commodity hedges were de-designated during the nine months ended September 30, 2017 and 2016. We estimate that approximately $48.7 million, representing net losses from our cash flow hedging activities based on pricing and positions at September 30, 2017, will be reclassified from AOCI to earnings during the next 12 months.

24
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)


Effect of Derivative Instruments on the Consolidated Statements of Income and Accumulated Other Comprehensive Income
Derivatives in Cash Flow Hedging Relationships
 
Amount of Gain
(Loss) Recognized
in AOCI on
Derivative
(Effective Portion)
 
Location of Gain
(Loss) Reclassified from
AOCI to Earnings
(Effective Portion)
 
Amount of Gain
(Loss) Reclassified
from AOCI
to Earnings
(Effective Portion)
 
Location of Gain (Loss)
Recognized in Earnings on
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness Testing)(1)
 
Amount of Gain
(Loss) Recognized in
Earnings on
Derivative (Ineffective
Portion and Amount
Excluded from
Effectiveness
Testing)(1)
 
 
 
 
 
 
 
 
 
 
 
  
 
  
 
(in millions)
 
  
 
  
Three months ended September 30, 2017
 
 
 
 
 
  

 
  
 
  

Interest rate contracts
 
$
(1.9
)
 
Interest expense
 
$
(9.8
)
 
Interest expense
 
$
(0.3
)
Total
 
$
(1.9
)
 
 
 
$
(9.8
)
 
 
 
$
(0.3
)
Three months ended September 30, 2016
 
 
 
 
 
  

 
  
 
  

Interest rate contracts
 
$
6.9

 
Interest expense
 
$
(10.0
)
 
Interest expense
 
$
—

Commodity contracts
 
—

 
Commodity costs
 
0.1

 
Commodity costs
 
—

Total
 
$
6.9

 
 
 
$
(9.9
)
 
 
 
$
—

Nine months ended September 30, 2017
 
 
 
 
 
  

 
  
 
  

Interest rate contracts
 
$
(17.7
)
 
Interest expense
 
$
(30.5
)
 
Interest expense
 
$
(2.2
)
Total
 
$
(17.7
)
 
 
 
$
(30.5
)
 
 
 
$
(2.2
)
Nine months ended September 30, 2016
 
 
 
 
 
  

 
  
 
  

Interest rate contracts
 
$
(128.3
)
 
Interest expense
 
$
(29.9
)
 
Interest expense
 
$
(3.4
)
Commodity contracts
 
—

 
Commodity costs
 
0.2

 
Commodity costs
 
—

Total
 
$
(128.3
)
 
 
 
$
(29.7
)
 
 
 
$
(3.4
)
_____________________
(1)
Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.
Components of Accumulated Other Comprehensive Income/(Loss)
 
Cash Flow Hedges
  
2017
 
2016
 
 
 
 
  
(in millions)
Balance at January 1
$
(339.3
)
 
$
(370.0
)
Other comprehensive loss before reclassifications
(24.5
)
 
(134.3
)
Amounts reclassified from AOCI(1)
30.5

 
29.7

Net other comprehensive income (loss)
6.0

 
(104.6
)
Balance at September 30
$
(333.3
)
 
$
(474.6
)
_____________________
(1)
For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

25
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)


Reclassifications from Accumulated Other Comprehensive Income
 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
  
 
(in millions)
 
  
Losses on cash flow hedges:
  

 
  

 
  

 
  

Interest Rate Contracts(1)
$
9.8

 
$
10.0

 
$
30.5

 
$
29.9

Commodity Contracts
—

 
(0.1
)
 
—

 
(0.2
)
Total Reclassifications from AOCI
$
9.8

 
$
9.9

 
$
30.5

 
$
29.7

_____________________
(1)
Loss reported within “Interest expense, net” in the consolidated statements of income.

Effect of Derivative Instruments on Consolidated Statements of Income
 
 
 
 
Three months ended September 30,
 
Nine months ended September 30,
  
 
 
 
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
 
 
 
Derivatives Not Designated
as Hedging Instruments
 
Location of Gain or (Loss)
Recognized in Earnings
 
Amount of Gain or (Loss)
Recognized in Earnings(1)(2)
 
Amount of Gain or (Loss)
Recognized in Earnings(1)(2)
 
 
 
 
 
 
 
 
 
  
 
  
 
  
 
(in millions)
 
  
Commodity contracts
 
Transportation and other services
(3) 
 
$
(1.3
)
 
$
1.0

 
$
1.8

 
$
(2.1
)
Total
$
(1.3
)
 
$
1.0

 
$
1.8

 
$
(2.1
)
_____________
(1)
Does not include settlements associated with derivative instruments that settle through physical delivery.
(2)
Includes only net gains or losses associated with those derivatives that do not receive hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.
(3)
Includes settlement gains of $0.4 million and $1.2 million for the three months ended September 30, 2017 and 2016, respectively, and settlement gains of $0.8 million and $4.9 million for the nine months ended September 30, 2017 and 2016, respectively.
We record the fair market value of our derivative financial and physical instruments in the consolidated statements of financial position as current and long-term assets or liabilities on a gross basis. However, the terms of the ISDA®, which govern our financial contracts and our other master netting agreements, allow the parties to elect in respect of all transactions under the agreement, in the event of a default and upon notice to the defaulting party, for the non-defaulting party to set-off all settlement payments, collateral held and any other obligations (whether or not then due), which the non-defaulting party owes to the defaulting party. The effect of the rights of set-off are outlined below.
Offsetting of Financial Assets and Derivative Assets
 
September 30, 2017
  
Gross
Amount of
Recognized
Assets
 
Gross
Amount
Offset in the
Statement of
Financial Position
 
Net Amount
of Assets
Presented in
the Statement of
Financial Position
 
Gross Amount
Not Offset in the
Statement of
Financial Position
 
Net Amount
  
  
 
  
 
(in millions)
 
  
 
  
Description:
  

 
  

 
  

 
  

 
  

Derivatives
$
0.1

 
$
—

 
$
0.1

 
$
(0.1
)
 
$
—



26
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)


 
December 31, 2016
  
Gross
Amount of
Recognized
Assets
 
Gross
Amount
Offset in the
Statement of
Financial Position
 
Net Amount
of Assets
Presented in
the Statement of
Financial Position
 
Gross Amount
Not Offset in the
Statement of
Financial Position
 
Net Amount
  
  
 
  
 
(in millions)
 
  
 
  
Description:
  

 
  

 
  

 
  

 
  

Derivatives
$
—

 
$
—

 
$
—

 
$
—

 
$
—


Offsetting of Financial Liabilities and Derivative Liabilities

 
September 30, 2017
  
Gross
Amount of
Recognized
Liabilities
 
Gross Amount
Offset in the
Statement of
Financial Position
 
Net Amount of Liabilities
Presented in
the Statement of
Financial Position
 
Gross Amount
Not Offset in the
Statement of
Financial Position
 
Net Amount
  
  
 
  
 
(in millions)
 
  
 
  
Description:
  

 
  

 
  

 
  

 
  

Derivatives
$
(185.7
)
 
$
—

 
$
(185.7
)
 
$
0.1

 
$
(185.6
)

 
December 31, 2016
  
Gross
Amount of
Recognized
Liabilities
 
Gross Amount
Offset in the
Statement of
Financial Position
 
Net Amount of
Liabilities
Presented in
the Statement of
Financial Position
 
Gross Amount
Not Offset in the
Statement of
Financial Position
 
Net Amount
  
  
 
  
 
(in millions)
 
  
 
  
Description:
  

 
  

 
  

 
  

 
  

Derivatives
$
(166.7
)
 
$
—

 
$
(166.7
)
 
$
—

 
$
(166.7
)
Inputs to Fair Value Derivative Instruments
The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2017 and December 31, 2016. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our valuation of the financial assets and liabilities and their placement within the fair value hierarchy. For the periods ended September 30, 2017 and December 31, 2016, we did not have any Level 3 derivative instruments.
 
 
September 30, 2017
 
December 31, 2016
  
 
Level 2
 
Level 2
 
 
 
 
 
  
 
  
 
  
Interest rate contracts
 
$
(185.0
)
 
$
(165.1
)
Commodity contracts:
 
  

 
  

Financial
 
(0.6
)
 
(1.6
)
Total
 
$
(185.6
)
 
$
(166.7
)

27
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)


Qualitative Information about Level 2 Fair Value Measurements
We categorize, as Level 2, the fair value of assets and liabilities that we measure with either directly or indirectly observable inputs as of the measurement date, where pricing inputs are other than quoted prices in active markets for the identical instrument. This category includes both OTC transactions valued using exchange traded pricing information in addition to assets and liabilities that we value using either models or other valuation methodologies derived from observable market data. These models are primarily industry-standard models that consider various inputs including: (i) quoted prices for assets and liabilities; (ii) time value; and (iii) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the assets and liabilities, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace.
Fair Value Measurements of Commodity Derivatives
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps at September 30, 2017 and December 31, 2016.

 
September 30, 2017
 
December 31, 2016
  
Commodity
 
Notional(1)
 
Wtd. Average Price(2)
 
Fair Value(3)
 
Fair Value(3)
  
Receive
 
Pay
 
Asset
 
Liability
 
Asset
 
Liability
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
  
 
  
 
  
 
  
 
(in millions)
Portion of contracts maturing in 2017
 
  

 
  

 
  

 
  

 
  

 
  

 
  

Swaps
  
 
  

 
  

 
  

 
  

 
  

 
  

 
  

Receive fixed/pay variable
Crude Oil
 
123,832

 
$
51.91

 
$
51.98

 
$
0.1

 
$
(0.1
)
 
$
—

 
$
(1.6
)
Portion of contracts maturing in 2018
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Swaps
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Receive fixed/pay variable
Crude Oil
 
498,955

 
$
50.71

 
$
51.85

 
$
—

 
$
(0.6
)
 
$
—

 
$
—

_____________
(1)
Volumes of crude oil are measured in Bbl.
(2)
Weighted-average prices received and paid are in $/Bbl for crude oil.
(3)
The fair value is determined based on quoted market prices at September 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of nil at September 30, 2017 and December 31, 2016, as well as cash collateral received.
Fair Value Measurements of Interest Rate Derivatives
We enter into interest rate swaps, caps and derivative financial instruments with similar characteristics to manage the cash flow associated with future interest rate movements on our indebtedness. The following table provides information about our current interest rate derivatives for the specified periods.
 
 
 
 
 
 
Average
Fixed
Rate(1)
 
Fair Value(2) at
Date of Maturity & Contract Type
 
Accounting Treatment
 
Notional
 
September 30,
2017
 
December 31,
2016
 
 
 
 
 
 
 
 
 
 
 
  
 
  
 
  
 
(dollars in millions)
 
  
Contracts maturing in 2017
 
 
 
 
 
 
 
 
 
 
Interest Rate Swaps – Pay Fixed
 
Cash Flow Hedge
 
$500
 
2.21%
 
$
—

 
$
(0.3
)
Contracts maturing in 2018
 
  
 
  
 
  
 
  

 
  

Interest Rate Swaps – Pay Fixed
 
Cash Flow Hedge
 
$810
 
2.24%
 
$
(2.1
)
 
$
(9.4
)
Contracts maturing in 2019
 
  
 
  
 
  
 
  

 
  

Interest Rate Swaps – Pay Fixed
 
Cash Flow Hedge
 
$620
 
2.96%
 
$
(7.8
)
 
$
(7.3
)
Contracts settling prior to maturity
 
  
 
  
 
  
 
  

 
  

2017 – Pre-issuance Hedges
 
Cash Flow Hedge
 
$1,000
 
4.07%
 
$
(156.0
)
 
$
(136.2
)
2018 – Pre-issuance Hedges
 
Cash Flow Hedge
 
$350
 
3.08%
 
$
(19.4
)
 
$
(13.1
)
_____________

28
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)


(1)
Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate (LIBOR).
(2)
The fair value is determined from quoted market prices at September 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustment gains of approximately $0.3 million and $1.2 million at September 30, 2017 and December 31, 2016, respectively.
13. SUPPLEMENTAL CASH FLOW INFORMATION
The “Cash used in investing activities” section of the consolidated statements of cash flows exclude changes that do not affect cash. The following is a reconciliation of cash used for capital expenditures to total capital expenditures (excluding “Investment in joint venture”):
 
Nine months ended September 30,
  
2017
 
2016
 
 
 
 
  
(in millions)
Total capital expenditures (excluding “Investment in joint venture”)
$
417.6

 
$
655.4

Decrease in construction payables
0.2

 
182.9

Cash used for capital expenditures
$
417.8

 
$
838.3


14. RELATED PARTY TRANSACTIONS
Administrative and Workforce Related Services
We do not directly employ any of the individuals responsible for managing or operating our business nor do we have any directors. Enbridge and its affiliates provide management and we obtain managerial, administrative, operational and workforce related services from our General Partner, Enbridge Management and affiliates of Enbridge pursuant to service agreements among our General Partner, Enbridge Management, affiliates of Enbridge, and us. Pursuant to these service agreements, we have agreed to reimburse our General Partner, Enbridge Management and affiliates of Enbridge, for the cost of managerial, administrative, operational and director services they provide to us. Where directly attributable, the cost of all compensation, benefits expenses and employer expenses for these employees are charged directly by Enbridge to the appropriate affiliate. Enbridge does not record any profit or margin for the administrative and operational services charged to us.
The affiliate amounts incurred by us for services received pursuant to the services agreements are reflected in “Operating and administrative — affiliate” on our consolidated statements of income.
Enbridge and its affiliates allocated direct workforce costs to us for our construction projects of $4.8 million as of September 30, 2017 and $28.4 million as of December 31, 2016, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.
Affiliate Revenues
We record operating revenues in our Liquids segment for storage, transportation and terminalling services we provide to affiliates, which are presented in “Transportation and other services — affiliate” on our consolidated statements of income.
Enbridge Pipelines (FSP) LLC Cushing Terminal Transfer
In August 2017, Enbridge Pipelines (FSP) L.L.C., (FSP), a wholly-owned subsidiary of our General Partner, completed an asset transfer of a capital project which involves modification and upgrades to the existing Cushing terminal facilities that are owned by our subsidiary, Enbridge Storage (Cushing) L.L.C. The transfer of assets was accounted for as a transaction between entities under common control as both FSP and we are related through common ownership by the General Partner. As of September 30, 2017, the assets were transferred at cost of $67.6 million and were recognized as a capital contribution from our General Partner.
Sale of Accounts Receivable
We and certain of our subsidiaries were parties to a receivables purchase agreement (the Receivables Agreement), with an indirect, wholly-owned subsidiary of Enbridge. On April 27, 2017, we terminated our Receivables Agreement with the indirect, wholly-owned subsidiary of Enbridge in exchange for a one-time $5.0 million payment to us, which was recorded within “Other income” in our consolidated statements of income.

29
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
14. RELATED PARTY TRANSACTIONS – (continued)


As a result of the termination of the Receivables Agreement we discontinued the sale of our receivables balance. For the three months ended September 30, 2017, no receivables were sold and derecognized. We sold and derecognized receivables of $429.6 million for the three months ended September 30, 2016. For the nine months ended September 30, 2017 and 2016, we sold and derecognized receivables of $458.0 million and $1,323.9 million, respectively, to an indirect, wholly-owned subsidiary of Enbridge. We received no cash proceeds for the three months ended September 30, 2017 and received $457.7 million for the nine months ended September 30, 2017. We received cash proceeds of $429.4 million and $1,323.3 million for the three and nine months ended September 30, 2016, respectively.
Consideration for the receivables sold was equivalent to the carrying value of the receivables less a discount for credit risk. The difference between the carrying value of the receivables sold and the cash proceeds received was recognized in “Operating and administrative — affiliate” expense in our consolidated statements of income. For the three and nine months ended September 30, 2017 and 2016, the expense stemming from the discount on the receivables sold was not material.
As of September 30, 2017, we had no remaining derecognized receivables that had not been collected on behalf of the Enbridge subsidiary. As of December 31, 2016, we had $155.5 million of receivables, which had been sold and derecognized that had not been collected on behalf of the Enbridge subsidiary.
Financial Transactions with Affiliates
EUS Credit Agreement
In connection with our investment in the Bakken Pipeline System, on February 15, 2017, we entered into the EUS Credit Agreement. The EUS Credit Agreement was a committed senior unsecured revolving credit facility that permitted aggregate borrowings of up to, at any one time outstanding for the purpose of funding our investment in the Bakken Pipeline System, $1.5 billion, (i) on a revolving basis for a 364-day period and (ii) for a 364-day term on a non-revolving basis following the expiration of the revolving period; provided that the EUS Credit Agreement would mature on the date any project financing was completed. Loans under the EUS Credit Agreement accrued interest based, at our election, on either the Eurocurrency rate or a base rate, in each case, plus an applicable margin. A facility fee accrued at the applicable margin rate, which is based on our non-credit-enhanced, senior unsecured long-term debt rating at the applicable time.
On April 27, 2017, we re-paid the facility in full and terminated the EUS Credit Agreement.
EUS 364-day Credit Facility
We are party to an unsecured revolving 364-day credit agreement (the EUS 364-day Credit Facility), with EUS. The EUS 364-day Credit Facility is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $750 million, (i) on a revolving basis for a 364-day period and (ii) for a 364-day term on a non-revolving basis following the expiration of the revolving period. Loans under the EUS 364-day Credit Facility accrue interest, at our election, based on either the Eurocurrency rate or a base rate, in each case, plus an applicable margin. On July 25, 2017 we entered into an agreement with EUS whereby the termination date was extended to July 24, 2018. The terms of our agreement with EUS remain unchanged. At that time, we may elect to convert any outstanding loans to term loans, which would mature on July 23, 2019. As of September 30, 2017, we had $544.0 million outstanding under this facility, excluding any accrued interest to date.
The commitment under the EUS 364-day Credit Facility may be permanently reduced by EUS, from time to time, by up to an amount equal to the net cash proceeds to us from the sale by us of debt or equity securities in a registered public offering.
Distribution from MEP
The following table presents distributions paid by MEP prior to its sale on June 28, 2017, representing the noncontrolling interest in MEP, and to us for our ownership of Class A common units. No distributions were made during the third quarter of 2017.
Distribution
Declaration Date
 
Distribution
Payment Date
 
Amount Paid to
EEP
 
Amount Paid to
Noncontrolling
Interest
 
Total MEP
Distribution
 
 
 
 
 
 
 
 
 
  
 
  
 
  
 
(in millions)
 
  
January 26, 2017
 
February 14, 2017
 
$
8.9

 
$
7.6

 
$
16.5

Distribution from DakTex

30
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
14. RELATED PARTY TRANSACTIONS – (continued)


The following table presents distributions paid by DakTex during the nine months ended September 30, 2017, to our General Partner and its affiliates, representing NCI in Class A units of DakTex, and to us, as the holders of the remaining Class A units of DakTex.
Distribution
Declaration Date
 
Distribution
Payment Date
 
Amount Paid to
EEP
 
Amount Paid to
Noncontrolling
Interest
 
Total DakTex
Distribution
 
 
 
 
 
 
 
 
 
  
 
  
 
  
 
(in millions)
 
  
September 25, 2017
 
September 29, 2017
 
$
10.2

 
$
30.7

 
$
40.9

We along with our General Partner made capital contributions of $420.0 million to DakTex for the nine months ended September 30, 2017. Equity income for the three and nine months ended September 30, 2017, were $21.7 million and $28.1 million, respectively, of which 75% is attributable to our General Partner and recorded as part of NCI.
Joint Funding Arrangement for Bakken Pipeline
On April 27, 2017, we finalized the joint funding arrangement with our General Partner with respect to our investment in the Bakken Pipeline System. Under the terms of the arrangement, our General Partner owns 75% and we own 25% of DakTex, with an option for us to increase our interest by 20% at a price equal to net book value, at any time during the five years subsequent to the June 1, 2017 in-service date of the Bakken Pipeline System. We received distributions from DakTex in the amount of $1.14 billion during the second quarter of 2017. The funds received were used to repay our borrowing, under the EUS Credit Agreement.
Joint Funding Arrangement for Line 3 Replacement
On January 26, 2017, our Board of Directors approved a joint funding arrangement with our General Partner for the U.S. L3R Program. Under the terms of the arrangement, our General Partner will fund 99% and we will fund 1% of the capital cost of the U.S. L3R Program. We have an option to increase our interest in the U.S. L3R Program assets up to 40% in the U.S. portion at book value at any time up to four years after the project goes into service. Our General Partner paid $450.1 million for its 99% interest in the project, including our share of the construction costs to date and other incremental amounts. The carrying amount of our 99% interest in the project at the transaction date was $411.0 million and was recorded as an increase to noncontrolling interest. The $39.1 million difference between the cash received and the carrying amount was recorded as an increase to the capital accounts of our common units, i-units, and General Partner interest on a pro-rated basis.
Our General Partner made equity contributions totaling $185.0 million to the OLP for the nine months ended September 30, 2017, to fund its equity portion of the construction costs associated with the U.S. L3R Program.
Joint Funding Arrangement for Eastern Access Projects
We have a joint funding arrangement with the General Partner that established an additional series of partnership interests in the OLP (the EA interest). The EA interests were created to finance the Eastern Access Project to increase access to refineries in the U.S. Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States.
On January 26, 2017, we exercised our option under the Eastern Access joint funding arrangement to acquire an additional 15% interest in the Eastern Access Project, thereby increasing our ownership interest from 25% to 40% and reducing the interest of our General Partner from 75% to 60%, respectively. The exercise of our option occurred at book value of approximately $360 million and reduced noncontrolling interest by approximately $360 million. The Eastern Access Project was placed into service in June 2016.
Our General Partner made equity contributions totaling $8.5 million and $7.2 million to the OLP for the nine months ended September 30, 2017 and 2016, respectively, to fund its equity portion of the construction costs associated with the Eastern Access Project.
Distribution to Series EA Interests
The following table presents distributions paid by the OLP during the nine months ended September 30, 2017, to our General Partner and its affiliate, representing the noncontrolling interest in the Series EA, and to us, as the holders of the Series EA general partner interests and certain limited partner interests.

31
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
14. RELATED PARTY TRANSACTIONS – (continued)


Distribution
Declaration Date
 
Distribution
Payment Date
 
Amount Paid to
EEP
 
Amount Paid to
Noncontrolling Interest
 
Total Series EA
Distribution
  
 
  
 
  
 
(in millions)
 
  
July 28, 2017
 
August 14, 2017
 
$
33.2

 
$
49.8

 
$
83.0

April 27, 2017
 
May 15, 2017
 
29.3

 
62.0

 
91.3

January 26, 2017
 
February 14, 2017
 
22.9

 
68.8

 
91.7

  
 
 
 
$
85.4

 
$
180.6

 
$
266.0


Joint Funding Arrangement for U.S. Mainline Expansion Projects
The OLP also has a series of partnership interests (the ME interests). The ME interests were created to finance the Mainline Expansion Projects to increase access to the markets of North Dakota and western Canada for light oil production on our Lakehead system between Neche, North Dakota and Superior, Wisconsin. Our General Partner owns 75% of the ME interests, and the projects are jointly funded by our General Partner at 75% and us at 25% with an option for us to increase our ownership interest by an additional 15% at cost, under the Mainline Expansion joint funding arrangement.
Our General Partner has made equity contributions totaling $27.3 million and $58.5 million to the OLP for the nine months ended September 30, 2017 and 2016, respectively, to fund its equity portion of the construction costs associated with the Mainline Expansion Projects.
Distribution to Series ME Interests
The following table presents distributions paid by the OLP during the nine months ended September 30, 2017, to our General Partner and its affiliate, representing the noncontrolling interest in the Series ME, and to us, as the holders of the Series ME general partner and certain limited partner interests.

Distribution
Declaration Date
 
Distribution
Payment Date
 
Amount Paid to
EEP
 
Amount Paid to
Noncontrolling
Interest
 
Total Series ME
Distribution
  
 
  
 
  
 
(in millions)
 
  
July 28, 2017
 
August 14, 2017
 
$
13.8

 
$
41.3

 
$
55.1

April 27, 2017
 
May 15, 2017
 
12.7

 
38.0

 
50.7

January 26, 2017
 
February 14, 2017
 
14.2

 
42.7

 
56.9

  
 
 
 
$
40.7

 
$
122.0

 
$
162.7


15. COMMITMENTS AND CONTINGENCIES
Environmental Liabilities
We are subject to federal and state laws and regulations relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us. Environmental risk is inherent to liquid hydrocarbon pipeline operations, and we are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through environmental policies and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with the operating activities of our liquids businesses. Our General Partner has agreed to indemnify us from and against any costs relating to environmental liabilities associated with the Lakehead system assets prior to the transfer of these assets to us in 1991. This excludes any liabilities resulting from a change in laws after such transfer. We continue to voluntarily investigate past leak sites on our systems for the purpose of assessing whether any remediation is required in light of current regulations.

32
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
15. COMMITMENTS AND CONTINGENCIES – (continued)


As of September 30, 2017 and December 31, 2016, our consolidated statements of financial position included $18.1 million and $99.8 million, respectively, in “Environmental liabilities,” and $57.4 million and $50.8 million, respectively, in “Other long-term liabilities,” that we have accrued for costs to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids assets and penalties we have been or expect to be assessed.
Lakehead Line 6B Crude Oil Release
On July 26, 2010, a release of crude oil on Line 6B of our Lakehead system was reported near Marshall, Michigan. We estimate that approximately 20,000 barrels of crude oil were leaked at the site, a portion of which reached the Kalamazoo River via Talmadge Creek, a waterway that feeds the Kalamazoo River. The released crude oil affected approximately 38 miles of shoreline along the Talmadge Creek and Kalamazoo River waterways, including residential areas, businesses, farmland and marshland between Marshall and downstream of Battle Creek, Michigan.
We continue to evaluate the need for additional remediation activities and are performing the necessary restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives we are undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the applicable regulatory authorities.
As of September 30, 2017, our cumulative cost estimate for the Line 6B crude oil release remains at $1.2 billion. For purposes of estimating our expected losses associated with the Line 6B crude oil release, we have included those costs that we considered probable and that could be reasonably estimated at September 30, 2017. Our estimates exclude: (i) amounts we have capitalized, (ii) any claims associated with the release that may later become evident, (iii) amounts recoverable under insurance, and (iv) fines and penalties from other governmental agencies except as described in the Line 6B Fines and Penalties section below. Our assumptions include, where applicable, estimates of the expected number of days the associated services will be required and rates that we have obtained from contracts negotiated for the respective service and equipment providers. As we receive invoices for the actual personnel, equipment and services, our estimates will continue to be further refined. Our estimates also consider currently available facts, existing technology and presently enacted laws and regulations. These amounts also consider our and other companies’ prior experience remediating contaminated sites and data released by government organizations. Despite the efforts we have made to ensure the reasonableness of our estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. We continue to have the potential of incurring additional costs in connection with this crude oil release due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims.
The components underlying our cumulative estimated loss for the cleanup, remediation and restoration associated with the Line 6B crude oil release, the majority of which have been paid, include the following:
 
(in millions)
Response personnel and equipment
$
547.3

Environmental consultants
224.3

Professional, regulatory, fines and penalties and other
443.4

Total
$
1,215.0


For the nine months ended September 30, 2017 and 2016, we made payments of $74.2 million and $17.3 million, respectively, for costs associated with the Line 6B crude oil release. As of September 30, 2017 and December 31, 2016, we had a remaining estimated liability of $64.1 million and $138.8 million, respectively.
Line 6B Fines and Penalties
At September 30, 2017, our total estimated costs related to the Line 6B crude oil release include $68.5 million in paid fines and penalties, which includes fines and penalties paid to the United States Department of Justice (DOJ) as discussed below.

33
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
15. COMMITMENTS AND CONTINGENCIES – (continued)


Consent Decree
On May 23, 2017, the United States District Court for the Western District of Michigan, Southern Division (the District Court), approved the Consent Decree (the Consent Decree), which is our signed settlement agreement with the United States Environmental Protection Agency and the DOJ regarding the Lines 6A and 6B crude oil releases, both of which occurred in 2010. On June 15, 2017, Enbridge made a total payment of $67.8 million as required by the Consent Decree, which reflects a $61.0 million civil penalty for the Line 6B release, a $1.0 million civil penalty for the Line 6A release, and $5.8 million for past removal costs and interest.
In addition to the monetary fines and penalties, the Consent Decree calls for replacement of Line 3, which we initiated in 2014 and is currently under regulatory review in the State of Minnesota; refer to Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Result of Operations-By Segment — Expansion Projects - Commercially Secured Projects — U.S.Line 3 Replacement Program for further details. The Consent Decree contains a variety of injunctive measures, including, but not limited to, enhancements to our comprehensive in-line inspections (ILI)-based spill prevention program; enhanced measures to protect the Straits of Mackinac; improved leak detection requirements; installation of new valves to control product loss in the event of an incident; continued enhancement of control room operations; and improved spill response capabilities. Collectively, these measures build on continuous improvements we have implemented since 2010 to our leak detection program, control center operations, and emergency response program. We estimate the total cost of these measures to be approximately $110 million, most of which is already incorporated into existing long-term capital investment and operational expense planning and guidance. Compliance with the terms of the Consent Decree is not expected to materially impact our overall financial performance.
Insurance
We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates. On May 1 of each year, our insurance program is renewed and includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and includes coverage for environmental incidents such as those we have incurred for the crude oil release from Line 6B, excluding costs for fines and penalties.
Enbridge, together with us and its other affiliates, are covered under comprehensive property and liability insurance programs under which we are insured through April 30, 2018, with a liability program aggregate limit of $940.0 million, which includes sudden and accidental pollution liability. In the event that multiple insurable incidents which in aggregate exceed coverage limits occur within the same insurance period, the total insurance coverage will be allocated among the Enbridge entities on an equitable basis based on an insurance allocation agreement we have entered into with Enbridge and other Enbridge subsidiaries.
A majority of the costs incurred for the July 2010 Line 6B crude oil release, other than fines and penalties, are covered by the insurance policies that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability for Enbridge and its affiliates. Including our remediation spending through September 30, 2017, costs related to Line 6B exceeded the limits of the coverage available under these insurance policies. Through September 30, 2017, we have recorded total insurance recoveries of $547.0 million for the Line 6B crude oil release, out of the $650.0 million aggregate limit.
In March 2013, we and Enbridge filed a lawsuit against the insurers of $145.0 million of coverage, as one particular insurer disputed our recovery eligibility for costs related to our claim on the Line 6B crude oil release and the other remaining insurers asserted that their payment was predicated on the outcome of our recovery with that insurer. We received a partial recovery payment of $42.0 million from the other remaining insurers and amended our lawsuit such that it included only one insurer.
Of the remaining $103.0 million coverage limit, $85.0 million was the subject matter of a lawsuit Enbridge filed against one particular insurer described above. In March 2015, Enbridge reached agreement with that insurer to submit the $85.0 million claim to binding arbitration. On May 2, 2017, the arbitration panel issued a decision that was not favorable to Enbridge. As a result, we will not receive any additional insurance recoveries in connection with the Line 6B crude oil release.
Legal and Regulatory Proceedings
We are subject to various legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits by special interest groups. Some of these proceedings are covered, in whole or in part, by insurance.
We are in the early stages of discovery in relation to a unitholder derivative action, with trial scheduled in the second quarter of 2018. Accordingly, an estimate of reasonably possible losses, if any, associated with causes of action cannot be made until all of the facts, circumstances and legal theories relating to such claims and the defenses are fully disclosed and analyzed. We have

34
ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)
15. COMMITMENTS AND CONTINGENCIES – (continued)


not established any reserves relating to this action. We believe the action is without merit and expect to vigorously defend against it. We believe an unfavorable outcome to be more than remote but less than probable.
A number of governmental agencies and regulators initiated investigations into the Line 6B crude oil release. As at September 30, 2017, there are no claims pending against us in United States state courts in connection with the Line 6B crude oil release.
We have accrued a provision for future legal costs and probable losses associated with the Line 6B crude oil release as described above in this footnote.
16. SUBSEQUENT EVENTS
Distribution to Partners
On October 25, 2017, the board of directors of Enbridge Management declared a distribution payable to our partners on November 14, 2017. The distribution will be paid to unitholders of record as of November 7, 2017 of our available cash of $160.9 million at September 30, 2017, or $0.35 per limited partner unit. Of this distribution, $129.7 million will be paid in cash, $30.6 million will be distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $0.6 million will be retained from our General Partner from amounts otherwise distributable to it in respect of its general partner interest and limited partner interest to maintain its 2% general partner interest.
Distribution to Series EA Interests
On October 25, 2017 the managing general partner of the Series EA interests, declared a distribution payable to the holders of the Series EA general and limited partner interests. The OLP will pay $51.4 million to the noncontrolling interest in the Series EA, while $34.3 million will be paid to us.
Distribution to Series ME Interests
On October 25, 2017, the managing general partner of the Series ME interests declared a distribution payable to the holders of the Series ME general and limited partner interests. The OLP will pay $44.2 million to the noncontrolling interest in the Series ME, while $14.7 million will be paid to us.


35

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Item 1. Financial Statements of this report and in conjunction with the audited consolidated financial statements and accompanying footnotes in our Annual Report on Form 10-K for the year ended December 31, 2016, as filed with the Securities and Exchange Commission (SEC) on February 17, 2017.
RECENT DEVELOPMENTS
Alberta Clipper (Line 67) Presidential Permit
On October 16, 2017, we received a Presidential Permit for Line 67, following a nearly five- year process of review. Line 67 currently operates under an existing Presidential Permit that was issued by the United States Department of State in 2009 and the 2017 Presidential Permit authorizes us to fully utilize its capacity across the border.
Line 67 is a key component of the Lakehead system, which United States refineries rely on to provide vital products to consumers across the midwest United States. Refer to Results of Operations - by Segment — Expansion Projects — Commercially Secured Projects — Lakehead System Mainline Expansion for further information.
STRATEGIC REVIEW
Our ultimate parent, Enbridge, recently completed a merger with Spectra Energy Corp. Enbridge had indicated that as part of the integration of the two companies, its U.S. sponsored vehicles, including us, would be reviewed in context of the combined enterprise.
On April 28, 2017, we announced the conclusion of our strategic review. We and our General Partner have taken the following actions to strengthen our financial position and outlook:
•
The reduction of our quarterly distribution from $0.583 per unit to $0.35 per unit or from $2.33 per unit to $1.40 per unit on an annualized basis;
•
The sale of all of our interests in our Midcoast gas gathering and processing business which closed on June 28, 2017, to our General Partner for $2.26 billion, including cash consideration of $1.31 billion and $953.0 million of existing outstanding indebtedness at MEP. A portion of these proceeds were used for other restructuring actions including the repayment of deferred distributions on our Series 1 Preferred Units, as discussed below;
•
The finalization of the joint funding arrangement for our investment in the Bakken Pipeline System in which our General Partner now owns a 75% interest, and we own a 25% interest with an option to acquire an additional 20% interest from our General Partner at net book value. Refer to Other Developments — Bakken Pipeline System for further information;
•
The redemption of our outstanding Series 1 Preferred Units held by the General Partner at face value of $1.2 billion which was funded with the proceeds from the issuance of Class A common units to our General Partner;
•
Subsequent to the Midcoast sale on June 28, 2017, we repaid $357.3 million in deferred distribution balance owed to our General Partner with the proceeds from the Midcoast sale; and
•
The restructuring of our capital structure and modification of our incentive distribution rights through the irrevocable waiver by a wholly-owned subsidiary of our General Partner of all of that subsidiary’s 66.1 million Class D units and 1,000 IDUs in consideration for issuance of a new class of units, Class F units. These units are entitled to (i) 13% of all distributions of available cash in excess of $0.295 per unit, but less than or equal to $0.35 per unit, and (ii) 23% of all distributions of available cash in excess of $0.35 per unit.
Previously, on January 26, 2017, we announced three additional strengthening actions to alleviate short-term capital expenditure requirements and enhance our cash flows as follows:
•
We entered into a joint funding arrangement with our General Partner for the U.S. L3R Program whereby our General Partner paid approximately $450 million for a 99% interest in the project, including our share of the construction costs to date and other incremental amounts. Refer to Expansion Projects — Commercially Secured Projects — U.S. Line 3 Replacement Program.
•
We acquired an additional 15% interest in the Eastern Access Project, at its book value of approximately $360 million, which is now in service. We utilized the funds received from the joint funding arrangement for the U.S. L3R Program to exercise our option under the Eastern Access joint funding arrangement.
•
MEP entered into the merger agreement with our General Partner, whereby, on April 27, 2017, our General Partner acquired, for cash, all the outstanding publicly held Class A common units of MEP.

36


RESULTS OF OPERATIONS — OVERVIEW
We provide services to our customers and returns for our unitholders through our liquids business, which consists of interstate pipeline transportation and storage of crude oil and liquid petroleum. On June 28, 2017 our General Partner acquired all of our ownership interests in our Midcoast gas gathering and processing business through the acquisition of all of our 48.4% interest in Midcoast Operating, L.P., all of our ownership interests in Midcoast Holdings, L.L.C., and all of our limited partnership interests in MEP. For further details regarding the Midcoast sale, refer to Item 1. Financial Statements, Note 6 - Dispositions, Asset Impairment and Discontinued Operations.
Our liquids business is conducted through three systems: our Lakehead, Mid-Continent and North Dakota systems. These systems largely consist of FERC regulated interstate crude oil and liquid petroleum pipelines, gathering systems and storage facilities. The Lakehead system, together with the Enbridge system in Canada, forms the longest liquid petroleum pipeline system in the world. Our Liquids systems generate revenues primarily from charging shippers a rate per barrel to gather, transport and store crude oil and liquid petroleum.
The results of our Midcoast gas gathering and processing business, which was acquired by our General Partner on June 28, 2017, are included in “Loss from discontinued operations” in our consolidated statements of income.
The following table reflects our operating income (loss) by business segment and corporate charges for the three and nine months ended September 30, 2017 and 2016:

 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
(in millions)
Operating income (loss)
  

 
  

 
  

 
  

Liquids
$
267.9

 
$
(446.8
)
 
$
855.4

 
$
179.1

Other
(1.7
)
 
(2.3
)
 
(9.1
)
 
(9.4
)
Total operating income (loss)
266.2

 
(449.1
)
 
846.3

 
169.7

Interest expense, net
(104.1
)
 
(103.4
)
 
(305.8
)
 
(301.2
)
Allowance for equity used during construction
12.2

 
10.0

 
33.2

 
35.7

Other income
21.8

 
0.6

 
33.2

 
0.9

Income (loss) before income taxes
196.1

 
(541.9
)
 
606.9

 
(94.9
)
Income tax benefit (expense)
(0.1
)
 
(1.6
)
 
0.4

 
(5.2
)
Income (loss) from continuing operations
196.0

 
(543.5
)
 
607.3

 
(100.1
)
Loss from discontinued operations, net of tax
—

 
(31.1
)
 
(56.8
)
 
(124.4
)
Net income (loss)
196.0

 
(574.6
)
 
550.5

 
(224.5
)
Less: Net income (loss) attributable to:
  

 
  

 
  

 
  

Noncontrolling interest
102.9

 
(191.9
)
 
261.8

 
(52.8
)
Series 1 preferred unit distributions
—

 
22.5

 
29.0

 
67.5

Accretion of discount on Series 1 preferred units
—

 
1.2

 
8.5

 
3.5

Net income (loss) attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.
$
93.1

 
$
(406.4
)
 
$
251.2

 
$
(242.7
)
Our Liquids segment operating income increased $714.7 million and $676.3 million for the three and nine months ended September 30, 2017, as compared to the same period in 2016. The increase in operating income was predominately attributable to the absence of a one-time impairment loss of $756.7 million in relation to the withdrawal of our regulatory application on the Sandpiper Project recognized in 2016.
We incurred a loss from discontinued operations of $56.8 million for the nine months ended September 30, 2017, which resulted from the sale of our Midcoast gathering and processing business during the second quarter of 2017 to our General Partner.
Other income increased $21.2 million and $32.3 million for the three and nine months ended September 30, 2017, respectively, as compared to the same period in 2016, mainly due to the equity earnings from the Bakken Pipeline System, which entered service on June 1, 2017.

37

Income attributable to NCI increased $294.8 million and $314.6 million for the three and nine months ended September 30, 2017, as compared to the same period in 2016. The increase is attributable to the absence of a one-time impairment loss of $756.7 million in relation to the withdrawal of our regulatory application on the Sandpiper Project of which $267.4 million was attributable to NCI. On June 28, 2017, we sold all our interest in our Midcoast gas gathering and processing business resulting in the absence of losses which were attributable to NCI.
Derivative Transactions and Hedging Activities
Contractual arrangements expose us to market risks associated with changes in (i) commodity prices where we receive crude oil in return for the services we provide or (ii) interest rates on our variable rate debt. Our unhedged commodity position is fully exposed to fluctuations in commodity prices, which can be significant during periods of price volatility. We use derivative financial instruments such as futures, forwards, swaps, options and other financial instruments with similar characteristics, to manage the risks associated with market fluctuations in commodity prices and interest rates, as well as to reduce variability in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates. Derivative financial instruments that do not receive hedge accounting under the provisions of authoritative accounting guidance create volatility in our earnings that can be significant. However, these fluctuations in earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument.
We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not receive hedge accounting in our consolidated statements of income as follows:
•
Liquids segment commodity-based derivatives — “Transportation and other services”
•
Interest rate derivatives — “Interest expense, net”
The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net changes in fair value associated with our derivative financial instruments:
 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
(in millions)
Liquids segment:
  

 
  

 
  

 
  

Non-qualified hedges
$
(1.7
)
 
$
(0.2
)
 
$
1.0

 
$
(7.0
)
Other:
  

 
  

 
  

 
  

Interest rate hedge ineffectiveness
(0.3
)
 
—

 
(2.2
)
 
(3.4
)
Derivative fair value net losses
$
(2.0
)
 
$
(0.2
)
 
$
(1.2
)
 
$
(10.4
)


38

RESULTS OF OPERATIONS — BY SEGMENT
Liquids
The following tables set forth the operating results and statistics of our Liquids segment assets for the periods presented:

 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
(in millions)
Operating Results:
  

 
  

 
  

 
  

Operating revenues
$
616.4

 
$
634.6

 
$
1,817.6

 
$
1,885.6

Operating expenses:
  

 
  

 
  

 
  

Environmental costs, net of recoveries
1.2

 
(8.7
)
 
15.0

 
8.3

Operating and administrative
160.9

 
149.7

 
464.9

 
418.6

Power
80.1

 
74.3

 
221.0

 
206.8

Depreciation and amortization
111.8

 
109.4

 
328.9

 
315.7

Gain on sale of assets
(5.5
)
 
—

 
(67.6
)
 
—

Asset impairment
—

 
756.7

 
—

 
757.1

Total operating expenses
348.5

 
1,081.4

 
962.2

 
1,706.5

Operating income (loss)
$
267.9

 
$
(446.8
)
 
$
855.4

 
$
179.1

Operating Statistics:
  

 
  

 
  

 
  

Lakehead system:
  

 
  

 
  

 
  

United States(1)
1,982

 
1,909

 
2,008

 
1,957

Canada(1)
638

 
586

 
649

 
601

Total Lakehead system delivery volumes(1)
2,620

 
2,495

 
2,657

 
2,558

Barrel miles (billions)
188

 
178

 
563

 
536

Average haul (miles)
782

 
774

 
776

 
765

Mid-Continent system delivery volumes(1)
—

 
217

 
33

 
200

North Dakota system delivery volumes(1)
303

 
363

 
330

 
382

Total Liquids segment delivery volumes(1)
2,923

 
3,075

 
3,020

 
3,140

_________________
(1)
Average Bpd in thousands.
Three months ended September 30, 2017, compared with the three months ended September 30, 2016
Operating income increased $714.7 million for the three months ended September 30, 2017, as compared to the same period in 2016. The increase in operating income is attributable to the absence of asset impairment changes in 2017, partially offset by lower operating revenue as discussed below.
Operating revenues. The $18.2 million decreases were mainly driven by:
•
A decrease in operating revenue from the Mid-Continent system which was due primarily to the sale of the Ozark Pipeline system on March 1, 2017.
•
While the North Dakota Pipeline is near capacity, lower operating revenue from the North Dakota system was primarily due to the expiration of Phase 5 and Phase 6 expansion surcharges and lower spot volumes on the Bakken Pipeline which is a component of the North Dakota system that delivers volume into Cromer, Manitoba.
•
Partially offset by an increase in operating revenue from the Lakehead system due to increased flow-through of recoverable operating costs attributable to higher throughput on the Lakehead system.
Operating expenses. The $732.9 million decrease was mainly driven by:
•
The absence of asset impairment charges in 2017. In third quarter 2016 the Sandpiper Project in North Dakota was impaired when the project's regulatory application was withdrawn.

39

•
Gain on sale of unnecessary pipe related to the Sandpiper Project.
•
Partially offset by higher environmental costs, net of recoveries, due to the Romeoville insurance recovery recognized in third quarter 2016.
•
Higher operating and administrative expenses predominately attributable to the write-off of an office lease due to consolidation of the Houston office facilities and higher property taxes, which were partially offset by lower expenses on the Ozark Pipeline system as it was sold on March 1, 2017.
•
Higher power expenses due to an increase in throughput volumes on the Lakehead system.
Nine months ended September 30, 2017, compared with the nine months ended September 30, 2016
Operating income increased $676.3 million, as compared to the same period in 2016. The increase in operating income is attributable to lower operating expenses, partially offset by lower operating revenue as discussed below.
Operating revenue. The $68.0 million decrease was mainly driven by:
•
Lower operating revenue from the North Dakota system due to the expiration of Phase 5 and Phase 6 expansion surcharges, as well as lower rail revenues to our Berthold rail facility as contracts on the facility expired.
•
A decrease in operating revenue from the Mid-Continent system due primarily to the sale of the Ozark Pipeline system on March 1, 2017 and lower storage and terminalling revenue for our Cushing system due to reduced activity that attracts volume dependent fee revenue.
•
Partially offset by an increase in operating revenue from the Lakehead system due to increased flow-through costs attributable to higher throughput. This increase was partially offset by lower average toll rates, as surcharges recognized in 2016 related to the recovery of hydrostatic testing costs on Line 2B expired in 2016.
Operating expenses. The $744.3 million decrease was mainly driven by:
•
The absence of asset impairment charges in 2017. In third quarter 2016 the Sandpiper Project was impaired.
•
Gains on asset disposals in 2017 including unnecessary pipe from the Sandpiper project and the Ozark Pipeline system.
•
An increase in environmental costs, net of recoveries due to environmental remediation costs related to a release on the Ozark Pipeline system on January 14, 2017 and the Romeoville insurance recovery recognized in third quarter 2016. The increase was partially offset by a cost accrual for estimated fines and penalties associated with the Line 6B crude oil release in the first quarter of 2016.
•
An increase in operating and administrative expenses due to higher property taxes, the write-off of a lease for the Houston office, lower capital expenditures in the current period resulting in less capitalization of project overhead associated with a smaller capital program, and Line 5 hydrostatic testing costs, partially offset by lower expenses on the Ozark Pipeline system as it was sold on March 1, 2017.
•
Increase in power expenses primarily due to higher throughput on the Lakehead system.
•
Increase in depreciation expense directly attributable to additional assets placed into service in 2016.
Expansion Projects — Commercially Secured Projects
The following table summarizes the status of our commercially secured projects for the Liquids segment. Expenditures to date reflect total cumulative expenditures incurred from inception of the project to September 30, 2017.
 
Estimated Capital
Costs(1)
 
Expenditures to
Date(2)
 
Expected
In-Service Date
 
Status
Lakehead System Mainline Expansion:
  
 
  
 
  
 
  
Line 61(3),(4)
0.4 billion
 
0.4 billion
 
2019
 
Substantially complete
U.S. Line 3 Replacement Program(5)
2.9 billion
 
0.6 billion
 
2019
 
Under construction
_________________
(1)
These amounts are estimates and are subject to upward or downward adjustment based on various factors.
(2)
Expenditures to date reflect total cumulative expenditures incurred from inception of the project up to September 30, 2017.
(3)
Jointly funded 25% by us and 75% by our General Partner under the Mainline Expansion Joint Funding Arrangement. Estimated capital costs are presented at 100% before our General Partner’s contributions.
(4)
Estimated in-service date will be adjusted to coincide with the in-service date of the U.S. L3R Program.

40

(5)
As discussed under U.S. Line 3 Replacement Program below, the Conflicts Committee and Board of Directors approved a joint funding arrangement with the General Partner for the U.S. Line 3 Replacement Program. The General Partner will fund 99% and we will fund 1% of the capital cost of the U.S. L3R Program.
Lakehead System Mainline Expansion
We and Enbridge have invested in a Light Oil Market Access Program to expand access to markets for growing volumes of light oil production. This program responds to significant developments with respect to supply of light oil from U.S. north central formations and western Canada, as well as refinery demand for light oil in the U.S. Midwest and eastern Canada. The remaining projects in the Light Oil Market Access Program will further expand capacity on our U.S. mainline system and provide additional access to U.S. Midwestern refineries.
The Lakehead System Mainline Expansion Project includes several projects to expand capacity of our Lakehead system mainline between Neche, North Dakota, and Flanagan, Illinois. These projects include the expansion of our existing 36-inch diameter Alberta Clipper pipeline (Line 67) and our existing 42-inch diameter Southern Access pipeline (Line 61) and construction of the Spearhead North Twin pipeline (Line 78). The expansion of Line 67 and construction of Line 78 were completed during 2015.
On October 16, 2017, the United States Department of State issued a Presidential Permit to us to operate Line 67 at its design capacity of 888,889 Bpd at the border of the United States and Canada near Neche,North Dakota.
In 2015, we completed the Line 61 expansion, between Superior, Wisconsin and Flanagan, Illinois, which increased the pipeline capacity to 950,000 Bpd. The expansion phase to increase the pipeline capacity to 1,200,000 Bpd at a total cost of approximately $0.4 billion was substantially completed in June of 2017. In conjunction with shippers, a decision was made to delay the in-service date of this remaining expansion phase to 2019 to align more closely with the anticipated in-service date for the U.S. L3R Program.
We operate the Lakehead System Mainline Expansions Projects on a cost-of-service basis. These Projects are jointly funded 75% by our General Partner and 25% by us under the Mainline Expansion Joint Funding Arrangement. We have the option to increase our economic interest held up to 15% at cost.
U.S. Line 3 Replacement Program
In 2014, we and Enbridge jointly announced that shipper support was received to replace portions of the existing 1,031-mile Line 3 pipeline on the Canadian Mainline/Lakehead system between Hardisty, Alberta, Canada and Superior, Wisconsin. The U.S. portion of the Line 3 replacement program includes replacing 358 miles from the U.S./Canadian border at Neche, North Dakota to Superior, Wisconsin. The U.S. L3R Program will support the safety and operational reliability of the system, enhance flexibility, allow us and Enbridge to optimize throughput on the mainline system, and will restore approximately 370,000 Bpd capacity from Western Canada into Superior, Wisconsin.
We are in the process of obtaining the appropriate permits for constructing the U.S. L3R Program in Minnesota. The project requires both a Certificate of Need (Certificate) and an approval of the pipeline’s route (Route Permit) from the MNPUC. The MNPUC found both the Certificate and Route Permit applications for the U.S. L3R Program through Minnesota to be complete. On February 1, 2016, the MNPUC issued a written order requiring the Minnesota Department of Commerce (DOC) to prepare an Environmental Impact Statement (EIS) before the Certificate and Route Permit processes commence. The DOC issued the final EIS on August 17, 2017. The MNPUC will determine its adequacy by December 2017. In the parallel Certificate and Route Permit dockets, progress continues according to schedule with public hearings currently underway. The MNPUC is expected to issue a ruling in the second quarter of 2018. Construction commenced on the Wisconsin portion of the U.S. Line 3 Replacement program in late June 2017.
Based on the updated execution plan, the revised cost of the project is $2.9 billion. This modest increase is roughly 12% above prior estimates and reflects the ongoing delays in the regulatory process, as well as some additional scope, route modifications and other changes as a result of the extensive consultation efforts and obligation to meet permit conditions. We will recover our costs plus a return on capital based on our existing Facilities Surcharge Mechanism (FSM) with the initial term being 15 years. For purposes of the toll surcharge, the agreement specifies a 30 year recovery of the capital based on a cost-of-service methodology.
On January 26, 2017, we entered into a joint funding arrangement with our General Partner for the U.S. L3R Program. Under the terms of the arrangement, our General Partner and we will fund 99% and 1% of the capital cost of the U.S. L3R Program, respectively. We have an option to increase our interest in the U.S. L3R Program’s assets to a total interest of up to 40% at book value at any time up to four years after the project goes into service. Our General Partner paid us approximately $450 million for its 99% interest in the project, including our share of the construction costs to date and other incremental amounts.

41

Other Developments
Bakken Pipeline System
On February 15, 2017, through our joint venture with MPC, we completed the acquisition of an effective 27.6% interest in the Bakken Pipeline System for a purchase price of $1.5 billion.We initially funded the $1.5 billion acquisition through the EUS Credit Agreement. On April 27, 2017, we finalized the joint funding arrangement with our General Partner for our effective interest in the Bakken Pipeline System. Under the terms of the arrangement, our General Partner owns 75% and we own 25% of DakTex, which in turn owns the joint venture with MPC. We also have a five-year option to acquire an additional 20% interest in DakTex at net book value. With the finalization of the joint funding arrangement, we repaid the $1.5 billion outstanding under the EUS Credit Agreement and terminated the credit agreement.
The Bakken Pipeline System, which consists of DAPL and ETCOP, was placed into service June 1, 2017. It transports crude oil from the Bakken formation in North Dakota to markets in eastern PADD II, and the U.S. Gulf Coast. DAPL consists of 1,172 miles of 30-inch pipeline from the Bakken/Three Forks production area in North Dakota to Patoka, Illinois. It is expected to initially deliver in excess of 470,000 Bpd of crude oil and has the potential to be expanded to 570,000 Bpd. ETCOP consists of 62 miles of new 30-inch diameter pipe, 686 miles of converted 30-inch diameter pipe, and 40 miles of converted 24-inch diameter pipe from Patoka, Illinois to Nederland, Texas.
In February 2017, the Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe (the Tribes) filed motions with the U.S. District Court for the District of Columbia (the Court) contesting the validity of the process used by the United States Army Corps of Engineers (Army Corps) to permit DAPL. The plaintiffs requested the Court order the operator to shut down the pipeline until the appropriate regulatory process is completed.
On June 14, 2017, the Court ruled that the Army Corps failed to adequately consider the impact of an oil spill on the hunting and fishing rights of the Tribes and ordered the Army Corps to reconsider those components of its environmental analysis. The Court did not rule on whether DAPL should cease operations, but on June 21, 2017, the Court established a briefing schedule pursuant to which the parties to the litigation were provided with an opportunity to submit written arguments on this issue. Final briefs were filed by the parties in late August 2017. On October 11, 2017, the Court issued an order that allows DAPL to continue operating while the Army Corps completes the additional environmental review required by the Court's June 14, 2017 order.
Renewal of Line 5 Easement
On January 4, 2017, the Tribal Council of the Bad River Band of Lake Superior Tribe of Chippewa Indians (the Band) issued a press release indicating that the Band had passed a resolution not to renew its interest in certain Line 5 easements through the Bad River Reservation. Line 5 is included within the Lakehead system. The Band’s resolution calls for decommissioning and removal of the pipeline from all Bad River tribal lands and watershed and could impact Enbridge’s ability to operate the pipeline on the Reservation. Since the Band passed the resolution, the parties have agreed to ongoing discussions with the objective of understanding and resolving the Band’s concerns on a long-term basis.
Natural Gas
The following table presents the operating results from discontinued operations of our Midcoast gas gathering and processing business, which have been segregated from our continuing operations in our consolidated statements of income:
 
Three months ended September 30,
 
Nine months ended September 30,
  
2017
 
2016
 
2017
 
2016
 
 
 
 
 
 
 
 
  
(in millions)
Net loss from discontinued operations
$
—

 
$
(31.1
)
 
$
(56.8
)
 
$
(124.4
)
Operating Statistics (MMBtu/d):
  

 
  

 
  

 
  

East Texas
—

 
894,000

 
877,000

 
924,000

Anadarko
—

 
606,000

 
514,000

 
632,000

North Texas
—

 
192,000

 
174,000

 
202,000

Total
—

 
1,692,000

 
1,565,000

 
1,758,000

NGL Production (Bpd)
—

 
67,588

 
63,389

 
70,932

Three months ended September 30, 2017, compared with the three months ended September 30, 2016
The absence of losses from discontinued operations for the three months ended September 30, 2017 is attributable to the sale of our Midcoast gas gathering and processing business to our General Partner on June 28, 2017.


42

Nine months ended September 30, 2017, compared with the nine months ended September 30, 2016
Net losses from discontinued operations decreased $67.6 million for the nine months ended September 30, 2017, compared to the same period in 2016. The decrease was mainly attributable to the following factors:
•
Net losses decreased due to the absence of three months of losses from our discontinued operations as a result of the sale of our Midcoast gas gathering and processing business to our General Partner on June 28, 2017.
•
Operating revenues decreased period over period due to a decrease in processing and storage margins, reduced natural gas throughput, and reduced NGL production volumes. These decreases were attributable to the continued low commodity price environment and reductions in drilling activity by producers in the areas we operated. The decrease in operating revenue was offset by changes in unrealized fair value gains and losses related to the revaluation of financial derivatives used to manage the profitability of transportation and storage transactions and exposure to movements in commodity prices on the value of inventory.
•
Net losses from discontinued operations included a loss attributable to an asset impairment charge incurred on certain trucking assets in 2016. No similar charge was recorded during the same period in 2017.
•
Operating and administrative costs decreased due to cost savings in the 2017 period as a result of workforce reductions, lower property taxes, and other cost reduction efforts.

LIQUIDITY AND CAPITAL RESOURCES
General
Our primary operating cash requirements consist of normal operating expenses, maintenance capital expenditures, funding requirements associated with environmental costs, distributions to our partners and payments associated with our risk management activities. We expect to fund our current and future short-term cash requirements for these items from our operating cash flows supplemented as necessary by issuances of commercial paper and borrowings under our Credit Facilities. Margin requirements associated with our derivative transactions are generally supported by letters of credit issued under our Credit Facilities.
Our current business strategy includes developing and expanding our existing business through organic growth and targeted acquisitions, in addition to the strategies and actions taken as discussed above under Strategic Review.
We expect to initially fund our long-term cash requirements for expansion projects and acquisitions, as well as retire our maturing and callable debt, first from operating cash flows and then from issuances of commercial paper and borrowings on our Credit Facilities. We expect to obtain permanent financing as needed through the issuance of additional equity and debt securities, which we will use to repay amounts initially drawn to fund these activities, although there can be no assurance that such financings will be available on favorable terms, if at all.
In the past, when we had attractive growth opportunities in excess of our own capital raising capabilities, our General Partner provided supplementary funding, or participated directly in projects, to enable us to undertake such opportunities. If in the future we have attractive growth opportunities that exceed capital raising capabilities, we could seek similar arrangements from our General Partner, but there can be no assurance that this funding can be obtained.
Available Liquidity
Our primary source of short-term liquidity is provided by our $1.5 billion commercial paper program, which is supported by our $2.0 billion multi-year unsecured revolving credit facility (the Credit Facility) and our $625.0 million credit agreement (the 364-day Credit Facility). We refer to the 364-day Credit Facility and the Credit Facility as our Credit Facilities. We access our commercial paper program primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the interest rates available to us for commercial paper are more favorable than the rates available under our Credit Facilities. At September 30, 2017, we had approximately $1,279.2 million in available credit under the terms of our Credit Facilities.
We are also party to an unsecured revolving 364-day credit agreement with EUS. The EUS 364-day Credit Facility is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $750.0 million. For the nine months ended September 30, 2017, we had net repayments of approximately $206.0 million under the terms of the EUS 364-day Credit Facility.
In addition to the EUS 364-day Credit Facility, we entered into the EUS Credit Agreement, for the sole purpose of providing interim financing for our investment in the Bakken Pipeline System. On April 27, 2017, we finalized the joint funding arrangement with our General Partner with respect to our investment in the Bakken Pipeline System. As a result of the joint funding arrangement, we repaid the outstanding balance of $1.5 billion under the EUS Credit Agreement. For further details on the joint funding arrangement, refer to Joint Funding Arrangements below.

43

For further details regarding our commercial paper program, our Credit Facilities, the EUS 364-day Credit Facility, refer to Item 1. Financial Statements, Note 9 - Debt.
As of September 30, 2017, although we had a working capital deficit of approximately $0.7 billion, we had approximately $1.5 billion of consolidated liquidity to meet our ongoing operational, investing and financing needs as described above, as well as the funding requirements associated with the environmental remediation costs resulting from the crude oil release on Line 6B.
The following table sets forth the consolidated liquidity available to us at September 30, 2017.
 
EEP
  
(in millions)
Cash and cash equivalents
$
28.3

Total commitments under the Credit Facilities
2,625.0

Total commitments under the EUS 364-day Credit Facility
750.0

Less: Amounts outstanding under the Credit Facilities
200.0

Amounts outstanding under the EUS 364-day Credit Facility
544.0

Principal amount of commercial paper outstanding
1,080.5

Letters of credit outstanding
65.3

Total
$
1,513.5


Capital Resources
Equity and Debt Securities
Execution of our growth strategy and completion of our planned construction projects contemplate our accessing the public and private equity and credit markets to obtain the capital necessary to fund these activities. We have issued a balanced combination of debt and equity securities to fund our expansion projects and acquisitions. Our internal growth projects and targeted acquisitions will require additional permanent capital and require us to bear the cost of constructing and acquiring assets before we begin to realize a return on them. From time to time, if the capital markets are constrained, our ability and willingness to complete future debt and equity offerings may be limited, which in turn, could affect our ability to execute our growth strategy or complete our planned construction projects. The timing of any future debt and equity offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.
Subject to the foregoing, from time to time, we may seek to satisfy liquidity needs through the issuance of registered debt or equity securities. We have a current shelf registration statement on Form S-3 that allows us to issue an unlimited amount of equity and debt securities in underwritten public offerings.
Joint Funding Arrangements
In order to obtain capital, we have explored, and may continue to explore, numerous options, including joint funding arrangements. For further details regarding our existing joint funding arrangements refer to Item 1. Financial Statements, Note 14 - Related Party Transactions.
Cash Requirements
Capital Spending
We categorize our capital expenditures as either maintenance capital or expansion capital expenditures. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment which are worn, obsolete or completing its useful lives. Expenditure levels will increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital will increase due to the growth of our pipeline systems and the aging of portions of these systems. Maintenance capital expenditures are expected to be funded by operating cash flows.
Expansion capital expenditures include our capital expansion projects and other projects that improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues and enable us to respond to governmental regulations and developing industry standards. We anticipate funding expansion capital expenditures temporarily through borrowing under the terms of our Credit Facility, with permanent debt and equity funding being obtained when appropriate.

44

We maintain a comprehensive integrity management program for our pipeline systems, which relies on the latest technologies that include internal pipeline inspection tools. These internal pipeline inspection tools identify internal and external corrosion, dents, cracking, stress corrosion cracking and combinations of these conditions. We regularly assess the integrity of our pipelines utilizing the latest generations of metal loss, caliper and crack detection internal pipeline inspection tools. We also conduct hydrostatic testing to determine the integrity of our pipeline systems. Accordingly, we incur substantial expenditures each year for our integrity management programs. We expect to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Under our capitalization policy, expenditures that replace major components of property or extend the useful lives of existing assets are capital in nature, while expenditures to inspect and test our pipelines are usually considered operating expenses.
We incurred capital expenditures of approximately $417.6 million for the nine months ended September 30, 2017, including $30.2 million of maintenance capital expenditures. Of those capital expenditures, $220.8 million were financed by contributions from our General Partner via joint funding arrangements. At September 30, 2017, we had approximately $308.6 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment in the future.
Acquisitions
We continue to assess ways to generate value for our unitholders, including reviewing opportunities that may lead to acquisitions or other strategic transactions, some of which may be material. We evaluate opportunities against operational, strategic and financial benchmarks before pursuing them. We expect to obtain the funds needed to make acquisitions through a combination of cash flows from operating activities, borrowings under our Credit Facilities, joint funding arrangements and the issuance of additional debt and equity securities. All acquisitions are considered in the context of the practical financing constraints presented by the capital markets.
As discussed above, on February 15, 2017, through our joint venture with MPC we acquired a minority stake in the Bakken Pipeline System. For further details regarding our funding arrangements refer to Other Developments — Bakken Pipeline System.
Forecasted Expenditures
We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. The following table sets forth our estimated maintenance and expansion capital expenditures, net of joint funding, of $386 million for the year ending December 31, 2017. We expect to receive funding of approximately $379 million from our General Partner based on our joint funding arrangements for the U.S. L3R Program, Eastern Access Projects and Mainline Expansion Projects. Although we anticipate making these expenditures in 2017, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, regulatory permitting, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets.

 
Amounts
attributable
to us
 
Amounts
attributable to
the General
Partner interest
 
Total Forecasted Expenditures(1)
  
(in millions)
 
(in millions)
 
(in millions)
Liquids Projects
  

 
 
 
 
Eastern Access Projects
$
8

 
$
12

 
$
20

U.S. Mainline Expansions
20

 
60

 
80

Line 3 Replacement
3

 
307

 
310

Liquids Integrity Program
120

 
—

 
120

Expansion Capital
180

 
—

 
180

Maintenance Capital Expenditures
55

 
—

 
55

Total
$
386

 
$
379

 
$
765

_________________
(1)
Amounts do not include forecasted Allowance for Funds Used During Construction (AFUDC).



45

Distributions
The following table sets forth our distributions, as approved by the board of directors of Enbridge Energy Management during the nine months ended September 30, 2017.

Distribution Declaration Date
 
Record Date
 
Distribution
Payment Date
 
Distribution
per Unit
 
Cash
Available for
Distribution
 
Amount of
Distribution
of i-units
to i-unit
Holders(1)
 
Retained
from
General
Partner(2)
 
Distribution
of Cash
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
 
  
 
  
 
  
 
(in millions, except per unit amounts)
 
  
July 28, 2017
 
August 7, 2017
 
August 14, 2017
 
$
0.3500

 
$
160.2

 
$
30.0

 
$
0.6

 
$
129.6

April 27, 2017
 
May 8, 2017
 
May 15, 2017
 
$
0.3500

 
$
159.6

 
$
29.4

 
$
0.6

 
$
129.6

January 26, 2017
 
February 7, 2017
 
February 14, 2017
 
$
0.5830

 
$
264.8

 
$
47.7

 
$
1.0

 
$
216.1

_________________
(1)
We issued 1,000 i-units to Enbridge Management, the sole owner of our i-units, during 2017 in lieu of cash distributions.
(2)
We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us.
Environmental
Lakehead Line 6B Crude Oil Release
During the nine months ended September 30, 2017, our cash flows were affected by the approximately $74.2 million we paid for the environmental remediation, restoration and cleanup activities resulting from the crude oil release that occurred in 2010 on Line 6B of our Lakehead system. For more information regarding cost estimates and fines and penalties, refer to Item 1. Financial Statements, Note 15 - Commitments and Contingencies.
Derivative Activities
The following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative financial instruments based upon the market values at September 30, 2017 for each of the indicated calendar years:

 
Notional(1)
 
2017
 
2018
 
2019
 
2020
 
2021 & Thereafter
 
Total
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
(in millions)
Swaps:
  

 
  

 
  

 
  

 
  

 
  

 
  

Crude Oil
622,787

 
$
—

 
$
(0.6
)
 
$
—

 
$
—

 
$
—

 
$
(0.6
)
Totals
622,787

 
$
—

 
$
(0.6
)
 
$
—

 
$
—

 
$
—

 
$
(0.6
)
_________________
(1)
Notional amounts for crude oil are recorded in Bbl.

46

The following table provides summarized information about the timing and estimated settlement amounts of our outstanding interest rate derivatives calculated based on implied forward rates in the yield curve at September 30, 2017 for each of the indicated calendar years:
 
Notional
 
2017
 
2018
 
2019
 
2020
 
2021
 
Total(1)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  
(in millions)
Interest Rate Derivatives
  

 
  

 
  

 
  

 
  

 
  

 
  

Interest Rate Swaps:
  

 
  

 
  

 
  

 
  

 
  

 
  

Floating to Fixed
$
1,430


$
(0.9
)

$
(7.2
)

$
(1.7
)

$
—


$
—


$
(9.8
)
Pre-issuance hedges
1,350


(156.1
)

(19.4
)

—


—


—


(175.5
)
Totals
$
2,780


$
(157.0
)

$
(26.6
)

$
(1.7
)

$
—


$
—


$
(185.3
)
_________________
(1)
Fair values exclude credit valuation adjustment gains of approximately $0.3 million at September 30, 2017.

Cash Flow Analysis
The following table summarizes the changes in cash flows by operating, investing and financing for each of the periods indicated:

 
Nine months ended September 30,
 
Variance
2017 vs. 2016
  
2017
 
2016
 
 
 
 
 
 
 
  
(in millions)
Total cash provided by (used in):
  

 
  

 
  

Operating activities
$
559.9

 
$
821.2

 
$
(261.3
)
Investing activities
(343.5
)
 
(832.4
)
 
488.9

Financing activities
(289.4
)
 
(78.0
)
 
(211.4
)
Net decrease in cash and cash equivalents
(73.0
)
 
(89.2
)
 
16.2

Cash and cash equivalents at beginning of year – continuing operations
101.3

 
130.1

 
(28.8
)
Cash and cash equivalents at end of period – continuing operations
$
28.3

 
$
40.9

 
$
(12.6
)

Operating Activities
Net cash provided by our operating activities decreased $261.3 million for the nine months ended September 30, 2017, compared to the same period in 2016, primarily due to decreased cash from net income after non-cash adjustments, as well as greater cash outflows from net changes in operating assets and liabilities. Decreased cash from net income after non-cash adjustments totaled $113.6 million and was primarily due to lower revenue from our liquids systems, as described in Results of Operations — by Segment.
Cash outflows from net changes in operating assets and liabilities increased $147.7 million. Our operating assets and liabilities fluctuate in the normal course of business due to various factors, including timing of cash payments and receipts.
Investing Activities
Net cash used in our investing activities during the nine months ended September 30, 2017, decreased by $488.9 million compared to the same period in 2016, primarily due to cash inflows of $1,310.0 million received from the sale of the Midcoast assets as well as cash inflows of $318.9 million from the sale of the Ozark Pipeline system during the first quarter 2017 and the sale of unnecessary pipe in relation to the Sandpiper Project during the second and third quarter of 2017. Further, contributing to cash inflows were lower spending on capital projects of $420.5 million million compared to the same period in 2016 as the remaining expansion of the Eastern Access Project was placed into service in June 2016. The increase in cash inflows was partially offset by outflows of $1,577.3 million from the acquisition of the Bakken Pipeline System.

47

Financing Activities
Net cash used in our financing activities increased $211.4 million for the nine months ended September 30, 2017 compared to the same period in 2016 primarily due to the following:
•
Net repayments on sources of short-term financing of $895.3 million;
•
Net repayments of $206.0 million under the EUS 364-day Credit Facility;
•
Cash outflow of $1,557.3 million used in the redemption of the Series 1 preferred units and payment of the deferred distribution on these units as we had no such redemptions for the nine months ended September 30, 2016;
•
Cash outflow of $360.3 million as a result of the acquisition of additional 15% interest in the Eastern Access Projects as we had no such acquisitions on projects under joint funding arrangements for the nine months ended September 30, 2016; and
•
Increased cash distributions to noncontrolling interest of $318.8 million due to suspension of cash distributions to our General Partner on the Series EA and ME during the nine months ended September 30, 2016. Distributions resumed during the nine months ended September 30, 2017.
These increases in net cash used in our financing activities were partially offset by the following:
•
Net proceeds of $1,224.5 million received from the issuance of Class A units as we had no such issuances for the nine months ended September 30, 2016; and
•
Increased contributions from NCI of $1,327.9 million as a result of the finalization of the joint funding arrangement with our General Partner with respect to our investment in the Bakken Pipeline System whereby our General Partner acquired 75% of DakTex and contribution from our General Partner to fund their equity portion of construction cost in relation to various joint funding arrangements.

REGULATORY MATTERS
FERC Transportation Tariffs
Lakehead System
Effective April 1, 2017, FERC Tariff No. 43.22.0 (the 2017 Tariff filing) adjusted transportation rates for capacity expansion projects tariff rate changes known as FSM. The FSM allows recovery of costs associated with particular shipper-approved projects through an incremental surcharge that is layered on top of the base index rates. The 2017 FSM surcharge reflected our projected costs for shipper-approved projects for 2017 and an adjustment for the difference between estimated and actual costs and throughput for the prior year or 2016. The surcharge is applicable to all volumes entering our system from the effective date of the tariff, which are recognized as revenue when the barrels are delivered, typically a period of approximately 30 days from the origination date.
The 2017 Tariff filing decreased our transportation rates for all movements on the Lakehead system. For example, the rate for heavy crude oil movements from the Canadian border to the Chicago, Illinois area was reduced by approximately $0.15 per barrel to approximately $2.43 per barrel and for an equivalent light crude oil movement the rate was reduced by approximately $0.13 per barrel to approximately $2.01 per barrel. These decreases were primarily the result of an adjustment for the difference between estimated and actual costs and throughput for 2016 combined with a decrease in forecasted capital additions and higher volumes for 2017.
Effective July 1, 2017, FERC Tariff No. 43.23.0 increased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporated the multiplier of 1.001985 issued by the FERC on May 12, 2017 in FERC Docket No. RM93-11-000.
North Dakota System
Effective January 1, 2017, FERC Tariff No. 3.22.0 decreased rates to reflect the expiration of the Phase 5 Looping and Phase 6 Mainline surcharges. These surcharges were cost-of-service based surcharges that were adjusted each year to actual costs and volumes and were not subject to the FERC indexing methodology. This filing decreased the average transportation rates for all crude oil movements to Clearbrook, Minnesota on the North Dakota system by an average of approximately $0.43 per barrel, to an average rate of approximately $1.33 per barrel.
Effective April 1, 2017, FERC Tariff No. 3.23.0 established an initial interconnection charge at Stanley, North Dakota to facilitate a new pipeline interconnection with a third party. The newly established interconnection rate of $0.11 per barrel is only charged to shippers utilizing this service.

48

Effective June 1, 2017, FERC Tariff No. 5.0.0, a joint tariff with Sacagawea Pipeline Company LLC went into effect to establish joint tariff rates for the transportation of crude petroleum for shippers from receipt points at Johnson’s Corner and Keene, North Dakota to Clearbrook, Minnesota.
Effective July 1, 2017, FERC Tariff No. 3.24.0 increased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporated the multiplier of 1.001985 issued by the FERC on May 12, 2017 in FERC Docket No. RM93-11-000. Additionally, as per the Transportation Services Agreement, or TSA, this tariff adjusted the operating cost charge component of the committed trunkline rates to Berthold, North Dakota to the actual operating costs and throughput volumes for 2016 and the forecasted operating costs and throughput for 2017.
Bakken System
Effective July 1, 2017, FERC Tariff No. 2.4.0 increased rates in compliance with the indexed rate ceilings allowed by the FERC, which incorporated the multiplier of 1.001985 issued by the FERC on May 12, 2017, in FERC Docket No. RM93-11-000.
Also effective July 1, 2017, FERC Tariff No. 3.6.0 adjusted rates in accordance with the TSA that was included in the Petition for Declaratory Order filed on August 26, 2010 in FERC Docket No. OR10-19-000. Additionally, as per the TSA, this tariff adjusted the operating cost charge component of the committed international joint rates to Cromer, Manitoba to the actual operating costs and throughput volumes for 2016 and the forecasted operating costs and throughput for 2017.

Item 3. Quantitative and Qualitative Disclosures About Market Risk
The following should be read in conjunction with the information presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, filed on February 17, 2017, in addition to information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There have been no material changes to that information other than as presented below.
Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations. Our interest rate risk exposure does not exist within any of our segments, but exists at the corporate level where our fixed and variable rate debt obligations are issued. We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in interest rates, as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating.
Interest Rate Derivatives
The table below provides information about our derivative financial instruments that we use to hedge the interest payments on our variable rate debt obligations that are sensitive to changes in interest rates and to lock in the interest rate on anticipated issuances of debt in the future. For interest rate swaps, the table presents notional amounts, the rates charged on the underlying notional amounts and weighted average interest rates paid by expected maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contract. Weighted average variable rates are based on implied forward rates in the yield curve at December 31, 2016.
Date of Maturity & Contract Type
 
Accounting Treatment
 
Notional
 
Average Fixed Rate(1)
 
Fair Value(2)
September 30,
2017
 
December 31,
2016
  
 
  
 
  
 
(dollars in millions)
 
 
Contracts maturing in 2017
 
 
 
 
 
 
 
 
 
 
Interest Rate Swaps – Pay Fixed
 
Cash Flow Hedge
 
$500
 
2.21%
 
$
—

 
$
(0.3
)
Contracts maturing in 2018
 
  
 
  
 
  
 
  

 
  

Interest Rate Swaps – Pay Fixed
 
Cash Flow Hedge
 
$810
 
2.24%
 
$
(2.1
)
 
$
(9.4
)
Contracts maturing in 2019
 
  
 
  
 
  
 
  

 
  

Interest Rate Swaps – Pay Fixed
 
Cash Flow Hedge
 
$620
 
2.96%
 
$
(7.8
)
 
$
(7.3
)
Contracts settling prior to maturity
 
  
 
  
 
  
 
  

 
  

2017 – Pre-issuance Hedges
 
Cash Flow Hedge
 
$1,000
 
4.07%
 
$
(156.0
)
 
$
(136.2
)
2018 – Pre-issuance Hedges
 
Cash Flow Hedge
 
$350
 
3.08%
 
$
(19.4
)
 
$
(13.1
)
_________________
(1)
Interest rate derivative contracts are based on the one-month or three-month LIBOR.

49

(2)
The fair value is determined from quoted market prices at September 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustment gains of approximately $0.3 million and $1.2 million at September 30, 2017 and December 31, 2016, respectively.
Fair Value Measurements of Commodity Derivatives
The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps at September 30, 2017 and December 31, 2016.
 
September 30, 2017
 
December 31, 2016
  
  
 
  
 
Wtd. Average Price(2)
 
Fair Value(3)
 
Fair Value(3)
  
Commodity
 
Notional(1)
 
Receive
 
Pay
 
Asset
 
Liability
 
Asset
 
Liability
  
  
 
  
 
  
 
  
 
(in millions)
Portion of contracts maturing in 2017
  
 
  

 
  

 
  

 
  

 
  

 
  

 
  

Swaps
  
 
  

 
  

 
  

 
  

 
  

 
  

 
  

Receive fixed/pay variable
Crude Oil
 
123,832

 
$
51.91

 
$
51.98

 
$
0.1

 
$
(0.1
)
 
$
—

 
$
(1.6
)
Portion of contracts maturing in 2018
  
 
  
 
  
 
  
 
  
 
  
 
  
 
  
Swaps
  
 
  
 
  
 
  
 
  
 
  
 
  
 
  
Receive fixed/pay variable
Crude Oil
 
498,955

 
$
50.71

 
$
51.85

 
$
—

 
$
(0.6
)
 
$
—

 
$
—

_________________
(1)
Volumes of crude oil are measured in Bbl.
(2)
Weighted-average prices received and paid are in $/Bbl for crude oil.
(3)
The fair value is determined based on quoted market prices at September 30, 2017 and December 31, 2016, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values exclude credit valuation adjustment gains of nil at September 30, 2017 and December 31, 2016, as well as cash collateral received.
Our credit exposure for OTC derivatives is directly with our counterparty and continues until the maturity or termination of the contract. When appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.
The table below summarizes our derivative balances by counterparty credit quality (negative amounts represent our net obligations to pay the counterparty):
 
September 30,
2017
 
December 31,
2016
  
(in millions)
Counterparty Credit Quality(1)
  

 
  

AA
$
(83.8
)
 
$
(79.2
)
A
(65.1
)
 
(58.4
)
Lower than A
(36.7
)
 
(29.1
)
  
$
(185.6
)
 
$
(166.7
)
_________________
(1)
As determined by nationally-recognized statistical ratings organizations.

50

Item 4. Controls and Procedures
We and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended (the Exchange Act), within the time periods specified in the rules and forms of the SEC, and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our principal executive and principal financial officers, has evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2017. Based upon that evaluation, our principal executive and principal financial officers concluded that our disclosure controls and procedures are effective at the reasonable assurance level. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting and other services on our behalf.
There have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the three months ended September 30, 2017.

51

PART II — OTHER INFORMATION

Item 1. Legal Proceedings
Refer to Part I, Item 1. Financial Statements, Note 15 - Commitments and Contingencies, which is incorporated herein by reference.
Brinckerhoff v. Enbridge Energy Co., Inc. et al.
On July 20, 2015, plaintiff Peter Brinckerhoff, individually and as trustee of the Peter R. Brinckerhoff Trust, filed a Verified Class Action and Derivative Complaint in the Court of Chancery of the State of Delaware against our General Partner, Enbridge, Enbridge Management, Enbridge Pipelines (Alberta Clipper) L.L.C., the OLP, us, and the following individuals: Jeffrey A. Connelly, Rebecca B. Roberts, Dan A. Westbrook, J. Richard Bird, J. Herbert England, C. Gregory Harper, D. Guy Jarvis, Mark A. Maki, and John K. Whelen, (collectively, the Director Defendants). The Complaint asserts both class action claims on behalf of holders of our Class A Common Units, as well as derivative claims brought on behalf of us. The plaintiff’s claims arise out of the January 2, 2015 repurchase by us of our General Partner’s 66.67% interest in the Alberta Clipper Pipeline (the 2015 Transaction). First, the plaintiff alleges that the 2015 Transaction improperly amended without Public Unitholder consent the Sixth Amended and Restated Agreement of Limited Partnership (the LPA) so as to allocate to the Public Unitholders taxable income that should have been allocated to the General Partner (the Special Tax Allocation). Second, the plaintiff alleges that we paid an unfair price for our General Partner’s 66.67% interest in the Alberta Clipper Pipeline such that the 2015 Transaction breached the LPA because it was not fair and reasonable to the Partnership. The Complaint asserts claims for breach of fiduciary duty, breach of the covenant of good faith and fair dealing, breach of residual fiduciary duties, tortious interference, aiding and abetting, and rescission and reformation.
On April 29, 2016, the court granted Enbridge’s and the Director Defendants’ motion to dismiss and dismissed the case in its entirety. On May 26, 2016 the Plaintiff appealed that dismissal to the Delaware Supreme Court. On March 20, 2017, the Delaware Supreme Court reversed in part and affirmed in part the ruling of the Court of Chancery. Specifically, the Delaware Supreme Court affirmed that the enactment of the Special Tax Allocation did not breach the LPA, but reversed on the question of whether the Plaintiff had adequately alleged that the price we paid in the 2015 Transaction, including the Special Tax Allocation component, was fair and reasonable to the Partnership. The parties are currently in the early stages of discovery, with trial scheduled in the second quarter of 2018.
Item 1A. Risk Factors
There have been no material changes to our risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, filed with the SEC on February 17, 2017.
Item 6. Exhibits
Reference is made to the “Index of Exhibits” following the signature page, which we hereby incorporate into this Item.

52

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 
Enbridge Energy Partners, L.P.
(Registrant)
  
 
  
  
By:
Enbridge Energy Management, L.L.C.
as delegate of
Enbridge Energy Company, Inc.
as General Partner
  
 
  
Date: November 1, 2017
By:
/s/ Mark A. Maki
 
 
Mark A. Maki
President
(Principal Executive Officer)
  
 
  
Date: November 1, 2017
By:
/s/ Christopher J. Johnston
 
 
Christopher J. Johnston
Vice President, Finance
(Principal Financial Officer)

53

Index of Exhibits

Each exhibit identified below is filed as a part of this Quarterly Report on Form 10-Q. Exhibits included in this filing are designated by an asterisk (“*”); all exhibits not so designated are incorporated by reference to a prior filing as indicated.

Exhibit Number
 
Description
 
 
 
 
 
 
101.INS* 
 
XBRL Instance Document.
101.SCH* 
 
XBRL Taxonomy Extension Schema Document.
101.CAL*
 
XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF* 
 
XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*
 
XBRL Taxonomy Extension Label Linkbase Document.
101.PRE* 
 
XBRL Taxonomy Extension Presentation Linkbase Document.

54

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