10-Q 1 v436410_10q.htm 10-Q

  

  

 

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 March 31, 2016
 
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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 
Large Accelerated Filer x   Accelerated Filer o
Non-Accelerated Filer  o (Do not check if a smaller reporting company)   Smaller reporting company 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 262,208,428 Class A common units outstanding as of May 2, 2016.

 

 


 
 

TABLE OF CONTENTS

ENBRIDGE ENERGY PARTNERS, L.P.
 
TABLE OF CONTENTS

 
PART I — FINANCIAL INFORMATION
        

Item 1.

Financial Statements

        
Consolidated Statements of Income for the three months ended March 31, 2016 and 2015     1  
Consolidated Statements of Comprehensive Income for the three months ended March 31, 2016
and 2015
    2  
Consolidated Statements of Cash Flows for the three months ended March 31, 2016 and 2015     3  
Consolidated Statements of Financial Position as of March 31, 2016 and December 31, 2015     4  
Notes to the Consolidated Financial Statements     5  

Item 2.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

    38  

Item 3.

Quantitative and Qualitative Disclosures About Market Risk

    57  

Item 4.

Controls and Procedures

    60  
PART II — OTHER INFORMATION
        

Item 1.

Legal Proceedings

    60  

Item 1A.

Risk Factors

    60  

Item 6.

Exhibits

    60  
Signatures     61  
Exhibits     62  

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) changes in the demand for the supply of, forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and natural gas liquids, or NGLs, including the rate of development of the Alberta Oil Sands; (2) our ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline systems; (4) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to which we sell products; (5) hazards and operating risks that may not be covered fully by insurance, including those related to Line 6B and any additional fines and penalties assessed in connection with the crude oil release on that line; (6) changes in or challenges to our tariff rates, (7) 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 (8) permitting at federal, state and local levels in regards to the construction of new assets.

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, 2015, which is available to the public over the Internet at the United States Securities and Exchange Commission’s, or SEC’s, website (www.sec.gov) and at our website (www.enbridgepartners.com).

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TABLE OF CONTENTS

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

ENBRIDGE ENERGY PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF INCOME

   
  For the three months
ended March 31,
     2016   2015
     (unaudited; in millions,
except per unit amounts)
Operating revenues:
                 
Commodity sales (Note 12)   $ 377.8     $ 800.9  
Commodity sales – affiliate (Notes 10 and 12)     5.2       21.8  
Transportation and other services (Note 12)     656.0       574.7  
Transportation and other services – affiliate (Note 10)     22.6       31.2  
       1,061.6       1,428.6  
Operating expenses:
                 
Commodity costs (Notes 5 and 12)     335.4       761.2  
Commodity costs – affiliate (Note 10)     12.6       17.9  
Environmental costs, net of recoveries (Note 11)     16.9       0.8  
Operating and administrative     96.5       98.2  
Operating and administrative – affiliate (Note 10)     118.5       118.9  
Power     72.8       63.6  
Depreciation and amortization     140.9       128.4  
       793.6       1,189.0  
Operating income     268.0       239.6  
Interest expense, net (Notes 8 and 12)     (112.9 )      (48.3 ) 
Allowance for equity used during construction (Note 16)     12.3       23.0  
Other income (Note 10)     7.5       5.9  
Income before income tax expense     174.9       220.2  
Income tax expense (Note 13)     (2.5 )      (2.4 ) 
Net income     172.4       217.8  
Less: Net income attributable to:
                 
Noncontrolling interest (Note 9)     68.8       51.3  
Series 1 preferred unit distributions     22.5       22.5  
Accretion of discount on Series 1 preferred units     1.1       3.9  
Net income attributable to general and limited partner ownership interests in
Enbridge Energy Partners, L.P.
  $ 80.0     $ 140.1  
Net income allocable to common units and i-units   $ 24.1     $ 85.9  
Net income per common unit and i-unit (basic and diluted) (Note 2)   $ 0.07     $ 0.26  
Weighted average common units and i-units outstanding (basic and diluted)     344.7       332.6  

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

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ENBRIDGE ENERGY PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

   
  For the three months
ended March 31,
     2016   2015
     (unaudited; in millions)
Net income   $ 172.4     $ 217.8  
Other comprehensive loss, net of tax expense (Note 12)     (77.6 )      (146.8 ) 
Comprehensive income     94.8       71.0  
Less:
                 
Net income attributable to noncontrolling interest (Note 9)     68.8       51.3  
Net income attributable to Series 1 preferred unit distributions     22.5       22.5  
Net income attributable to accretion of discount on Series 1 preferred units     1.1       3.9  
Other comprehensive loss allocated to noncontrolling interest           (0.7 ) 
Comprehensive income (loss) attributable to general and limited partner ownership
interests in Enbridge Energy Partners, L.P.
  $ 2.4     $ (6.0 ) 

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

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ENBRIDGE ENERGY PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF CASH FLOWS

   
  For the three months
ended March 31,
     2016   2015
     (unaudited; in millions)
Cash provided by operating activities:
                 
Net income   $ 172.4     $ 217.8  
Adjustments to reconcile net income to net cash provided by operating activities:
                 
Depreciation and amortization     140.9       128.4  
Derivative fair value net losses (Note 12)     30.7       10.3  
Inventory market price adjustments (Note 5)           4.6  
Environmental costs, net of recoveries (Note 11)     15.9       (0.2 ) 
Distributions from investments in joint ventures     7.1       5.7  
Equity earnings from investments in joint ventures     (7.1 )      (5.7 ) 
Allowance for equity used during construction     (12.3 )      (23.0 ) 
Amortization of debt issuance and hedging costs     10.6       2.8  
Other     (1.9 )      1.6  
Changes in operating assets and liabilities, net of acquisitions:
                 
Receivables, trade and other     9.8       10.6  
Due from General Partner and affiliates     (32.6 )      (55.6 ) 
Accrued receivables     35.6       190.4  
Inventory     19.8       56.2  
Current and long-term other assets     5.8       (13.9 ) 
Due to General Partner and affiliates     (30.3 )      12.9  
Accounts payable and other     (81.4 )      (36.2 ) 
Environmental liabilities     (5.0 )      (7.7 ) 
Accrued purchases     (32.1 )      (121.3 ) 
Interest payable     23.6       (0.8 ) 
Property and other taxes payable     (3.2 )      3.6  
Net cash provided by operating activities     266.3       380.5  
Cash used in investing activities:
                 
Additions to property, plant and equipment (Note 15)     (389.7 )      (460.0 ) 
Asset acquisitions           (85.1 ) 
Changes in restricted cash (Note 4)     11.6       40.4  
Investments in joint ventures           (1.9 ) 
Distributions from investments in joint ventures in excess of cumulative earnings     4.2       2.4  
Other     (0.5 )      0.2  
Net cash used in investing activities     (374.4 )      (504.0 ) 
Cash provided by financing activities:
                 
Net proceeds from unit issuances           294.8  
Distributions to partners (Note 9)     (216.0 )      (194.2 ) 
Repayments to General Partner           (306.0 ) 
Net borrowings under credit facilities (Note 8)     405.0       155.0  
Net commercial paper borrowings (repayments) (Note 8)     (136.4 )      165.0  
Contributions from noncontrolling interest (Note 10)     54.4       199.5  
Distributions to noncontrolling interest (Note 10)     (7.6 )      (107.0 ) 
Other     (0.8 )       
Net cash provided by financing activities     98.6       207.1  
Net increase (decrease) in cash and cash equivalents     (9.5 )      83.6  
Cash and cash equivalents at beginning of year     148.1       197.9  
Cash and cash equivalents at end of period   $ 138.6     $ 281.5  

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

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ENBRIDGE ENERGY PARTNERS, L.P.
 
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

   
  March 31,
2016
  December 31,
2015
     (unaudited; in millions)
ASSETS
                 
Current assets:
                 
Cash and cash equivalents (Note 4)   $ 138.6     $ 148.1  
Restricted cash (Note 4)     23.0       37.6  
Receivables, trade and other, net of allowance for doubtful accounts of $2.6 million and $2.5 million at March 31, 2016 and December 31, 2015, respectively     17.1       25.2  
Due from General Partner and affiliates (Note 10)     92.0       59.4  
Accrued receivables     42.3       77.9  
Inventory (Note 5)     15.3       35.1  
Other current assets (Notes 12 and 16)     143.7       173.0  
       472.0       556.3  
Property, plant and equipment, net (Notes 6 and 16)     17,572.6       17,412.4  
Intangible assets, net     274.6       280.0  
Other assets, net (Notes 10 and 12)     508.0       525.6  
     $ 18,827.2     $ 18,774.3  
LIABILITIES AND PARTNERS’ CAPITAL
                 
Current liabilities:
                 
Due to General Partner and affiliates (Note 10)   $ 160.6     $ 190.9  
Accounts payable and other (Notes 4, 12 and 16)     493.2       654.9  
Environmental liabilities (Note 11)     108.3       95.8  
Accrued purchases     114.0       146.1  
Interest payable     122.5       98.9  
Property and other taxes payable (Note 13)     100.5       103.7  
Current maturities of long-term debt (Note 8)     300.0       300.0  
       1,399.1       1,590.3  
Long-term debt (Note 8)     7,997.7       7,728.4  
Due to General Partner and affiliates (Note 10)     260.8       238.3  
Other long-term liabilities (Notes 11, 12 and 13)     354.4       305.2  
       10,012.0       9,862.2  
Commitments and contingencies (Note 11)
                 
Partners’ capital: (Note 9)
                 
Series 1 preferred units (48,000,000 authorized and issued at March 31, 2016 and December 31, 2015)     1,187.9       1,186.8  
Class D units (66,100,000 authorized and issued at March 31, 2016 and
December 31, 2015)
    2,517.5       2,517.6  
Class E units (18,114,975 authorized and issued at March 31, 2016 and
December 31, 2015)
    778.3       778.2  
Class A common units (262,208,428 authorized and issued at March 31, 2016 and December 31, 2015)            
Class B common units (7,825,500 authorized and issued at March 31, 2016 and December 31, 2015)            
i-units (75,911,421 and 73,285,739 authorized and issued at March 31, 2016 and December 31, 2015, respectively)     92.0       212.6  
Incentive distribution units (1,000 authorized and issued at March 31, 2016 and December 31, 2015)     495.1       495.0  
General Partner     131.9       147.4  
Accumulated other comprehensive loss (Note 12)     (447.6 )      (370.0 ) 
Total Enbridge Energy Partners, L.P. partners’ capital     4,755.1       4,967.6  
Noncontrolling interest (Note 9)     4,060.1       3,944.5  
Total partners’ capital     8,815.2       8,912.1  
     $ 18,827.2     $ 18,774.3  

Variable Interest Entities (VIEs) — see Note 7.

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

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. BASIS OF PRESENTATION

We have prepared the accompanying unaudited interim consolidated financial statements in accordance with generally accepted accounting principles in the United States of America, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, the unaudited interim consolidated financial statements do not include all the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of March 31, 2016, our results of operations for the three months ended March 31, 2016 and 2015, and our cash flows for the three months ended March 31, 2016 and 2015. We derived our consolidated statement of financial position as of December 31, 2015 from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015. Our results of operations for the three months ended March 31, 2016 and 2015, should not be taken as indicative of the results to be expected for the full year due to seasonal fluctuations in the supply of and demand for crude oil, seasonality of portions of our natural gas business, timing and completion of our construction projects, maintenance activities, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value and the effect of environmental costs and related insurance recoveries on our Lakehead system. Our unaudited interim consolidated financial statements should be read in conjunction with our audited consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

2. NET INCOME PER LIMITED PARTNER UNIT

We allocate our net income among our Series 1 Preferred Units, or Preferred Units, our General Partner interest and our limited partner units using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income attributable to our General Partner and our limited partners according to the distribution formula for available cash as set forth in our partnership agreement. We allocate our net income to our limited partners owning Class D units and Class E units equal to the distributions that they receive. We also allocate any earnings in excess of distributions to our General Partner and limited partners owning Class A and Class B common units and i-units utilizing the distribution formula for available cash specified in our partnership agreement. We allocate any distributions in excess of earnings for the period to our General Partner and limited partners owning Class A and B common units and i-units based on their sharing of losses of 2% and 98%, respectively, as set forth in our partnership agreement. We calculate distributions to the General Partner and limited partners based upon the distribution rates and percentages set forth in the following table:

     
                    Distribution Targets   Portion of Quarterly
Distribution Per Unit
  Percentage Distributed to
General Partner and
IDUs(1)
  Percentage Distributed to
Limited partners
Minimum Quarterly Distribution     Up to $0.5435       2 %      98 % 
First Target Distribution     > $0.5435       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 Incentive Distribution Unit holder, a wholly-owned subsidiary of our General Partner.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

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

We determined basic and diluted net income per limited partner unit as follows:

   
  For the three months
ended March 31,
     2016   2015
     (in millions, except per
unit amounts)
Net income   $ 172.4     $ 217.8  
Less: Net income attributable to:
                 
 Noncontrolling interest     (68.8 )      (51.3 ) 
 Series 1 preferred unit distributions     (22.5 )      (22.5 ) 
 Accretion of discount on Series 1 preferred units     (1.1 )      (3.9 ) 
Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P.     80.0       140.1  
Less: distributions:
                 
Incentive distributions     (5.2 )      (3.4 ) 
Distributed earnings attributed to our General Partner     (5.2 )      (5.0 ) 
Distributed earnings attributed to Class D and Class E units     (49.1 )      (48.0 ) 
Total distributed earnings to our General Partner, Class D and Class E units and IDUs     (59.5 )      (56.4 ) 
Total distributed earnings attributed to our common units and i-units     (201.7 )      (193.5 ) 
Total distributed earnings     (261.2 )      (249.9 ) 
Overdistributed earnings   $ (181.2 )    $ (109.8 ) 
Weighted average common units and i-units outstanding     344.7       332.6  
Basic and diluted earnings per unit:
                 
Distributed earnings per common unit and i-unit(1)   $ 0.59     $ 0.58  
Overdistributed earnings per common unit and i-unit(2)     (0.52 )      (0.32 ) 
Net income per common unit and i-unit (basic and diluted)(3)   $ 0.07     $ 0.26  

(1) 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.
(2) 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.
(3) For the three months ended March 31, 2016 and 2015, 43,201,310 anti-dilutive Preferred units, 66,100,000 anti-dilutive Class D units and 18,114,975 anti-dilutive Class E units were excluded from the if-converted method of calculating diluted earnings per unit.

3. ACQUISITIONS

On February 27, 2015, Midcoast Energy Partners, L.P., or MEP, acquired a midstream business in Leon, Madison and Grimes Counties, Texas. The acquisition consisted of a natural gas gathering system. MEP acquired the midstream business for $85.0 million in cash and a contingent future payment of up to $17.0 million.

Of the $85.0 million purchase price, $20.0 million was placed into escrow, pending the resolution of a legal matter and completion of additional wells connecting to the system within one year of the acquisition date. As of March 31, 2016, $6.0 million of these escrow funds has been classified as “Other assets, net” in our consolidated statements of financial position, pending the resolution of a legal matter. Since the acquisition date, MEP has released $11.0 million from escrow for additional wells connected to the system. During the first quarter of 2016, the remaining $3.0 million in escrow was returned to MEP as some of the additional wells were not connected to the system within one year of the acquisition date. For the three months ended March 31, 2016, a $3.0 million gain was recognized as an offset to “Operating and administrative” expense in our consolidated statements of income related to the return of these escrow funds.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

3. ACQUISITIONS  – (continued)

The purchase and sale agreement contained a provision whereby MEP would have been obligated to make future tiered payments of up to $17.0 million if volumes are delivered into the system at certain tiered volume levels over a five-year period. MEP determined at the time of the acquisition that the potential payment was contingent consideration. At the acquisition date, the fair value of this contingent consideration, using a probability-weighted discounted cash flow model was $2.3 million. The contingent consideration was re-measured on a fair value basis each quarter until December 31, 2015, which resulted in an addition to the liability of $0.3 million for accretion. During the three months ended March 31, 2016, MEP determined, based on current and forecasted volumes, that it is remote that it will be obligated to make any payments at the expiration of the five-year period. Consequently, the liability was reversed and a $2.6 million gain was recognized as an offset to “Operating and administrative” expense in our consolidated statements of income for the three months ended March 31, 2016.

4. CASH AND CASH EQUIVALENTS

We extinguish liabilities when a creditor has relieved us of our obligation, which occurs when our financial institution honors a check that the creditor has presented for payment. Accordingly, obligations for which we have made payments that have not yet been presented to the financial institution totaling approximately $8.5 million and $21.5 million at March 31, 2016, and December 31, 2015, respectively, are included in “Accounts payable and other” on our consolidated statements of financial position.

Restricted Cash

Restricted cash is comprised of the following:

   
  March 31,
2016
  December 31,
2015
     (in millions)
Cash collected on behalf of Enbridge subsidiary for accounts receivable
sales and not yet remitted to the Enbridge subsidiary (see Note 10)
  $ 23.0     $ 19.0  
Cash held in escrow for acquisitions (see Note 3)           6.0  
Cash collateral for derivative activities (see Note 11)           12.6  
     $ 23.0     $ 37.6  

5. INVENTORY

Our inventory is comprised of the following:

   
  March 31,
2016
  December 31,
2015
     (in millions)
Materials and supplies   $ 2.1     $ 2.2  
Crude oil inventory     0.1       1.6  
Natural gas and NGL inventory     13.1       31.3  
     $ 15.3     $ 35.1  

“Commodity costs” on our consolidated statements of income include charges totaling $4.6 million for the three months ended March 31, 2015, that we recorded to reduce the cost basis of our inventory of natural gas and NGLs, to reflect the current market value. For the three months ended March 31, 2016, we did not have any similar material charges related to our inventory of natural gas and NGLs.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

6. PROPERTY, PLANT AND EQUIPMENT

Our property, plant and equipment is comprised of the following:

   
  March 31,
2016
  December 31,
2015
     (in millions)
Land   $ 67.2     $ 62.9  
Rights-of-way     958.8       952.5  
Pipelines     10,415.9       10,376.3  
Pumping equipment, buildings and tanks     4,474.2       4,232.3  
Compressors, meters and other operating equipment     2,160.2       2,147.6  
Vehicles, office furniture and equipment     284.4       280.0  
Processing and treating plants     629.2       627.8  
Construction in progress     1,933.4       1,968.8  
Total property, plant and equipment     20,923.3       20,648.2  
Accumulated depreciation     (3,350.7 )      (3,235.8 ) 
Property, plant and equipment, net   $ 17,572.6     $ 17,412.4  

7. VARIABLE INTEREST ENTITIES

Principles of Consolidation

On January 1, 2016, we adopted Accounting Standards Update No. 2015-02, which amended consolidation guidance to, among other things, eliminate the specialized consolidation model and guidance for limited partnerships, including the presumption that the general partner should consolidate a limited partnership. As a result, we have determined that certain entities that we historically consolidated under this presumption are variable interest entities, or VIEs. Further, we determined that we are the primary beneficiary for these VIEs and will continue to consolidate these entities under the amended guidance. While the amended guidance did not impact our conclusion that such entities should be consolidated, because such entities are now considered VIEs, additional disclosures are necessary. We have applied this amended guidance retrospectively to our disclosures.

The consolidated financial statements include our accounts, and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. Where we conclude we are the primary beneficiary of a VIE, we consolidate the accounts of that entity.

We assess all aspects of our interests in an entity and use judgment when determining if we are the primary beneficiary. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. A reassessment of the primary beneficiary conclusion is conducted when there are changes in the facts and circumstances related to a VIE.

All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method.

Midcoast Energy Partners, L.P.

MEP is a publicly-traded Delaware limited partnership. As of March 31, 2016, we owned a 51.9% direct limited partner interest in MEP. In addition, we own MEP’s general partner, Midcoast Holdings GP, L.L.C. The public owns the remaining interests in MEP. We are the primary beneficiary of MEP because (1) through our ownership of MEP’s general partner and our majority limited partner interest, we have the power to direct the activities that most significantly impact MEP’s economic performance; and (2) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to MEP.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

7. VARIABLE INTEREST ENTITIES  – (continued)

As of March 31, 2016 and December 31, 2015, our consolidated statements of financial position include total assets of $5,140.3 million and $5,227.2 million, respectively, and total liabilities of $1,144.8 million and $1,220.7 million, respectively, related to MEP. The assets of MEP can only be used to settle their obligations. We do not have an obligation to provide financial support to MEP other than through certain contractual obligations, as prescribed by the terms of certain indemnities and guarantees, to pay specified liabilities of MEP.

Midcoast Operating, L.P.

Midcoast Operating is a Texas limited partnership. As of March 31, 2016, we and MEP owned 48.4% and 51.6%, respectively, of direct limited partner interest in Midcoast Operating. In addition, MEP owns Midcoast Operating’s general partner, Midcoast OLP GP, L.L.C. MEP is the primary beneficiary of Midcoast Operating because (1) through MEP’s ownership in Midcoast Operating’s general partner and majority limited partner interest, MEP has the power to direct the activities that most significantly impact Midcoast Operating’s economic performance; and (2) MEP has the obligation to absorb losses and the right to receive residual returns that potentially could be significant to Midcoast Operating. In addition, MEP is the entity within the related party group that is most closely associated with Midcoast Operating. As such, MEP consolidates Midcoast Operating. As discussed above, we consolidate MEP, and by extension also consolidate Midcoast Operating.

Enbridge Energy, Limited Partnership

Enbridge Energy, Limited Partnership, or OLP, is a Delaware limited partnership that has established several series of partnership interests. As of March 31, 2016, we owned, directly or indirectly, 100% of the general partner interests in each series of OLP, as well as 100% of the Series LH and Series AC limited partner interests in OLP. In addition, including our ownership of the general partner interests, we directly and indirectly owned 25% of the Series EA and Series ME interests in OLP. Our General Partner owns the remaining 75% interests in Series EA and Series ME in OLP. We are the primary beneficiary of OLP because (1) through our ownership of the general partner interests in each of the OLP’s series and our limited partner interests in each series, we have the power to direct the activities that most significantly impact OLP’s economic performance; and (2) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to OLP. In addition, we are the entity within the related party group that is most closely associated with OLP.

As of March 31, 2016 and December 31, 2015, our consolidated statements of financial position include total assets of $11,228.4 million and $11,074.9 million, respectively, and total liabilities of $857.7 million and $998.2 million, respectively, related to OLP. Only the assets of OLP can be used to settle OLP’s obligations. We currently do not have any obligation to provide financial support to OLP, although from time to time, we may provide certain indemnities and guarantees for payment of specified liabilities to third parties in the event that OLP becomes in default under contracts with those third parties.

North Dakota Pipeline Company, L.L.C.

North Dakota Pipeline Company, L.L.C., or NPDC, is a Delaware limited liability company. As of March 31, 2016, we directly owned 100% of the Class A units and 62.5% of the Class B units in NDPC. Williston Basin Pipeline LLC, or Williston, an affiliate of Marathon Petroleum Corporation, or MPC, owns the remaining 37.5% of Class B units in NDPC, which are used to fund the Sandpiper Project. We are the primary beneficiary of NDPC because (1) through our 100% ownership in NDPC’s Class A units and majority ownership in its Class B units, we have the power to direct the activities that most significantly impact NDPC’s economic performance; and (2) we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to NDPC.

As of March 31, 2016 and December 31, 2015, our consolidated statements of financial position include total assets of $1,753.9 million and $1,746.3 million, respectively, and total liabilities of $52.3 million and $84.8 million, respectively, related to NDPC. Only the assets of NDPC can be used to settle NDPC’s obligations. We currently do not have any obligation to provide financial support to NDPC, although from time to time we may provide certain indemnities and guarantees for payment of specified liabilities to third parties in the event that NDPC becomes in default under contracts with those third parties.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

7. VARIABLE INTEREST ENTITIES  – (continued)

The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in our consolidated balance sheet.

   
  March 31,
2016
  December 31,
2015
     (unaudited; in millions)
ASSETS
                 
Cash and cash equivalents   $ 116.2     $ 108.7  
Restricted cash   $ 14.6     $ 20.6  
Receivables, trade and other, net   $ 14.7     $ 22.8  
Due from General Partner and affiliates   $ 85.8     $ 51.9  
Accrued receivables   $ 41.2     $ 77.4  
Inventory   $ 15.3     $ 35.1  
Other current assets   $ 137.9     $ 165.3  
Property, plant and equipment, net   $ 16,918.7     $ 16,766.6  
Intangible assets, net   $ 274.4     $ 279.8  
Other assets, net   $ 503.8     $ 520.2  
LIABILITIES
                 
Due to General Partner and affiliates   $ 128.5     $ 123.4  
Accounts payable and other   $ 358.9     $ 534.2  
Environmental liabilities   $ 107.9     $ 95.7  
Accrued purchases   $ 112.9     $ 144.1  
Interest payable   $ 8.2     $ 8.7  
Property and other taxes payable   $ 98.1     $ 100.5  
Long-term debt   $ 1,037.5     $ 1,087.4  
Other long-term liabilities   $ 202.8     $ 209.7  

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

8. DEBT

The following table presents the primary components of our outstanding indebtedness with third parties and the weighted average interest rates associated with each component as of March 31, 2016, before the effect of our interest rate hedging activities. Our indebtedness with related parties is discussed in Note 10. Related Party Transactions.

     
  Interest
Rate
  March 31,
2016
  December 31,
2015
          (in millions)
EEP debt obligations:
                          
Commercial Paper(1)     1.378 %    $ 189.7     $ 326.1  
Credit Facilities due 2017 – 2020     1.686 %      1,565.0       1,110.0  
Senior Notes due December 2016     5.875 %      300.0       300.0  
Senior Notes due April 2018     6.500 %      400.0       400.0  
Senior Notes due March 2019     9.875 %      500.0       500.0  
Senior Notes due March 2020     5.200 %      500.0       500.0  
Senior Notes due October 2020     4.375 %      500.0       500.0  
Senior Notes due September 2021     4.200 %      600.0       600.0  
Senior Notes due October 2025     5.875 %      500.0       500.0  
Senior Notes due June 2033     5.950 %      200.0       200.0  
Senior Notes due December 2034     6.300 %      100.0       100.0  
Senior Notes due April 2038     7.500 %      400.0       400.0  
Senior Notes due September 2040     5.500 %      550.0       550.0  
Senior Notes due October 2045     7.375 %      600.0       600.0  
Junior subordinated notes due 2067     8.050 %      400.0       400.0  
OLP debt obligations:
                          
Senior Notes due October 2018     7.000 %      100.0       100.0  
Senior Notes due October 2028     7.125 %      100.0       100.0  
MEP debt obligations:
                          
MEP Credit Agreement     2.691 %      440.0       490.0  
MEP Series A Senior Notes due September 2019     3.560 %      75.0       75.0  
MEP Series B Senior Notes due September 2021     4.040 %      175.0       175.0  
MEP Series C Senior Notes due September 2024     4.420 %      150.0       150.0  
Total principal amount of debt obligations              8,344.7       8,076.1  
Other:
                          
Unamortized discount              (6.0 )      (6.2 ) 
Current maturities of long-term debt              (300.0 )      (300.0 ) 
Unamortized debt issuance costs           (41.0 )      (41.5 ) 
Total long term debt         $ 7,997.7     $ 7,728.4  

(1) Individual issuances of commercial paper generally mature in 90 days or less, but are supported by our Credit Facilities and are therefore considered long-term debt.

On January 1, 2016, we adopted Accounting Standards Update No. 2015-03, which requires us to present debt issuance costs in the balance sheet as a reduction to the carrying amount of the debt liability, rather than as an asset. We have retrospectively adopted this guidance for all periods presented. The adoption of this guidance did not have a material impact on our consolidated financial statements.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

8. DEBT  – (continued)

Interest Cost

Our interest cost for the three months ended March 31, 2016, and 2015, is comprised of the following:

   
  For the three months
ended March 31,
     2016   2015
     (in millions)
Interest cost incurred(1)   $ 122.0     $ 60.5  
Less: Interest capitalized     9.1       12.2  
Interest expense   $ 112.9     $ 48.3  

(1) Interest cost incurred increased period-over-period, due to an increase in our average outstanding debt balances outstanding and in part due to a decrease in unrealized losses for the three months ended March 31, 2015, that did not occur during the same period in 2016.

Credit Facilities and Commercial Paper

Our multi-year senior unsecured revolving credit facility, which we refer to as the Credit Facility, permits aggregate borrowings of up to, at any one time outstanding, $1.975 billion, a letter of credit subfacility and a swing line subfacility. The Credit Facility matures September 26, 2020; however, $175.0 million of commitments will expire on the original maturity date of September 26, 2018.

Our 364-day revolving credit agreement, which we refer to as the 364-Day Credit Facility, permits aggregate borrowings of up to $625.0 million: (1) on a revolving basis for a 364-day period, extendible annually at the lenders’ discretion, and (2) for a 364-day term on a non-revolving basis following the expiration of all revolving periods. The current revolving credit termination date is July 1, 2016.

At March 31, 2016, the Credit Facility and 364-Day Credit Facility, together referred to as the Credit Facilities, provide an aggregate amount of approximately $2.6 billion of bank credit, which we use to fund our general activities and working capital needs. The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. During the three months ended March 31, 2016, we had net borrowings of $455.0 million, which includes gross borrowings of $2,995.0 million and gross repayments of $2,540.0 million.

We are party to an uncommitted letter of credit arrangement, pursuant to which the lender may, on a discretionary basis and with no commitment, agree to issue standby letters of credit upon our request. The aggregate amount of this uncommitted letter of credit is not to exceed $175.0 million. While the letter of credit arrangement is uncommitted and issuance of letters of credit is at the lender’s sole discretion, we view this arrangement as a liquidity enhancement as it allows us to potentially reduce our reliance on utilizing our committed Credit Facilities for issuance of letters of credit to support our hedging activities.

Our commercial paper program provides for the issuance of up to an aggregate principal amount of $1.5 billion of commercial paper and is supported by our Credit Facilities. We access the commercial paper market primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the available interest rates we can obtain are lower than the rates available under our Credit Facilities. During the three months ended March 31, 2016, we had net repayments of approximately $136.4 million, which includes gross borrowings of $3,071.7 million and gross repayments of $3,208.1 million. Our policy is to limit the amount of commercial paper we can issue by the amounts available under our Credit Facility up to an aggregate principal amount of $1.5 billion.

Our policy is to maintain availability at any time under our Credit Facilities amounts that are at least equal to the amount of commercial paper that we have outstanding at any time.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

8. DEBT  – (continued)

At March 31, 2016, we had approximately $645.5 million available under the terms of our Credit Facilities, determined as follows:

 
  (in millions)
Total credit available under our Credit Facilities   $ 2,600.0  
Less: Amounts outstanding under our Credit Facilities     1,565.0  
 Principal amount of commercial paper outstanding     189.7  
 Letters of credit outstanding     199.8  
Total amount available at March 31, 2016   $ 645.5  

MEP Credit Agreement

MEP, Midcoast Operating, and their material subsidiaries are party to a senior revolving credit facility, which we refer to as the MEP Credit Agreement, which permits aggregate borrowings of up to $810.0 million, at any one time outstanding. The original term of the MEP Credit Agreement was three years with an initial maturity date of November 13, 2016, subject to four one-year requests for extensions. The MEP Credit Agreement’s current maturity date is September 30, 2018; however, $140.0 million of commitments expire on the original maturity date of November 13, 2016, and an additional $25.0 million of commitments expire on September 30, 2017. During the three months ended March 31, 2016, MEP had net repayments of approximately $50.0 million, which includes gross borrowings of $1,585.0 million and gross repayments of $1,635.0 million.

Debt Covenants

As of March 31, 2016, we and our consolidated subsidiaries were in compliance with the terms of our financial covenants under our consolidated debt agreements.

Fair Value of Debt Obligations

The carrying amounts of our outstanding commercial paper, borrowings under our Credit Facilities, and the MEP Credit Agreement approximate their fair values at March 31, 2016, and December 31, 2015, 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 MEP Credit Agreement are included with our long-term debt obligations 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 $6.0 billion and $5.9 billion at March 31, 2016, and December 31, 2015, 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.

9. PARTNERS’ CAPITAL

Distribution to Partners

The following table sets forth our distributions, as approved by the board of directors of Enbridge Energy Management, or Enbridge Management, during the three months ended March 31, 2016.

             
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)     
January 29, 2016   February 5, 2016   February 12, 2016   $0.5830   $259.6   $42.7   $0.9   $216.0

(1) We issued 2,625,681 i-units to Enbridge Management, the sole owner of our i-units, during 2016 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.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

9. PARTNERS’ CAPITAL  – (continued)

Changes in Partners’ Capital

The following table presents significant changes in partners’ capital accounts attributable to our General Partner and limited partners as well as the noncontrolling interests in our consolidated subsidiaries, for the three months ended March 31, 2016 and 2015.

   
  For the three months
ended March 31,
     2016   2015
     (in millions)
Series 1 Preferred interests
                 
Beginning balance   $ 1,186.8     $ 1,175.6  
Net income     22.5       22.5  
Accretion of discount on preferred units     1.1       3.9  
Distribution payable     (22.5 )      (22.5 ) 
Ending balance   $ 1,187.9     $ 1,179.5  
General and limited partner interests
                 
Beginning balance   $ 4,150.8     $ 4,156.2  
Proceeds from issuance of partnership interests, net of costs           294.8  
Net income     80.0       140.1  
Distributions     (216.0 )      (194.2 ) 
Acquisition of noncontrolling interest in subsidiary           403.7  
Ending balance   $ 4,014.8     $ 4,800.6  
Accumulated other comprehensive loss
                 
Beginning balance   $ (370.0 )    $ (211.4 ) 
Changes in fair value of derivative financial instruments reclassified to earnings     10.0       (1.0 ) 
Changes in fair value of derivative financial instruments recognized in other comprehensive loss     (87.6 )      (145.1 ) 
Ending balance   $ (447.6 )    $ (357.5 ) 
Noncontrolling interest
                 
Beginning balance   $ 3,944.5     $ 3,609.0  
Capital contributions     54.4       199.5  
Acquisition of noncontrolling interest in subsidiary           (403.7 ) 
Other comprehensive income (loss) allocated to noncontrolling interest           (0.7 ) 
Net income     68.8       51.3  
Distributions to noncontrolling interest     (7.6 )      (107.0 ) 
Ending balance   $ 4,060.1     $ 3,348.4  
Total partners’ capital at end of period   $ 8,815.2     $ 8,971.0  

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-rata basis. For the three months ended March 31, 2016, the carrying amounts for the capital accounts of the Class A and Class B common units were reduced below zero due to distributions to limited partners in excess of earnings attributable to such limited partners. As a result, the capital balances of the i-units and our General Partner interests were reduced by $125.7 million and $11.7 million, respectively, to cure the deficit balances in the Class A and Class B common units.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

9. PARTNERS’ CAPITAL  – (continued)

Noncontrolling Interests

We have noncontrolling interests in the following consolidated subsidiaries: OLP, NDPC, and MEP. The noncontrolling interest in the OLP arises from the joint funding arrangements with our General Partner and its affiliate to finance certain expansion projects on our Lakehead system, which we refer to as the Eastern Access and Mainline Expansion Projects. Noncontrolling interest in NDPC arises from our agreement Williston, an affiliate of MPC, to, among other things, fund 37.5% of the Sandpiper Project. Noncontrolling interest in MEP arises from its public unitholders’ ownership interests in MEP.

The following table presents the components of net income (loss) attributable to noncontrolling interests as presented on our consolidated statements of income:

   
  For the three months
ended March 31,
     2016   2015
     (in millions)
Alberta Clipper Interests   $     $ (0.8 ) 
Eastern Access Interests     51.5       44.8  
U.S. Mainline Expansion Interests     26.6       16.5  
Midcoast Energy Partners, L.P.     (9.3 )      (9.2 ) 
Total   $ 68.8     $ 51.3  

10. 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 $9.7 million and $7.3 million for the three months ended March 31, 2016 and 2015, respectively, that we recorded as additions to “Property, plant and equipment, net” on our consolidated statements of financial position.

Sale of Accounts Receivable

For the three months ended March 31, 2016 and 2015, we sold and derecognized receivables of $901.6 million and $1,095.9 million, respectively, to an indirect, wholly-owned subsidiary of Enbridge. As a result, for the three months ended March 31, 2016 and 2015, we received cash proceeds of $901.2 million and $1,095.6 million, respectively. Consideration for the receivables sold is 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 is recognized in “Operating and administrative — affiliate” expense in our consolidated statements of income. For the three months ended March 31, 2016 and 2015, the expense stemming from the discount on the receivables sold was not material.

As of March 31, 2016 and December 31, 2015, we had $23.0 million and $19.0 million, respectively, in “Restricted cash” on our consolidated statements of financial position, for cash collections related to sold and

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

10. RELATED PARTY TRANSACTIONS  – (continued)

derecognized receivables that have yet to be remitted to the Enbridge subsidiary. As of March 31, 2016 and December 31, 2015, outstanding receivables of $251.6 million and $317.0 million, respectively, which had been sold and derecognized, had not been collected on behalf of the Enbridge subsidiary.

Affiliate Revenues and Purchases

We purchase natural gas from third-parties, which subsequently generates operating revenues from sales to Enbridge and its affiliates. These transactions are entered into at the market price on the date of sale and are presented in “Commodity sales — affiliate” on our consolidated statements of income. We also record operating revenues in our Liquids segment for storage, transportation and terminaling services we provide to affiliates, which are presented in “Transportation and other services — affiliate” on our consolidated statements of income.

We also purchase natural gas from Enbridge and its affiliates for sale to third-parties at market prices on the date of purchase. Purchases of natural gas, NGLs, and crude oil from Enbridge and its affiliates are presented in “Commodity costs — affiliate” on our consolidated statements of income.

Related Party Transactions with Joint Ventures

We have a 35% aggregate indirect interest in the Texas Express NGL system, which is comprised of two joint ventures with third parties that together include a 593-mile NGL intrastate transportation pipeline and a related NGL gathering system. Our equity investment in the Texas Express NGL system at March 31, 2016 and December 31, 2015, was $368.0 million and $372.3 million, respectively, which is included on our consolidated statements of financial position in “Other assets, net.” For the three months ended March 31, 2016 and 2015, we recognized equity income of $7.1 million and $5.7 million, respectively, in “Other income” on our consolidated statements of income related to our investment in the system.

For the three months ended March 31, 2016 and 2015, we incurred $5.4 million and $5.8 million, respectively, of pipeline transportation and demand fees from the Texas Express NGL system for our Natural Gas segment. These expenses are recorded in “Commodity costs — affiliate” on our consolidated statements of income.

Our Natural Gas segment has made commitments to transport up to 120,000 barrels per day, or Bpd, of NGLs on the Texas Express NGL system through 2022. The current commitment level is 29,000 Bpd.

Financing Transactions with Affiliates

Distribution from MEP

The following table presents distributions paid by MEP during the three months ended March 31, 2016, to its public Class A common unitholders, representing the noncontrolling interest in MEP, and to us for our ownership of Class A common units.

       
Distribution
Declaration Date
  Distribution
Payment Date
  Amount
Paid to EEP
  Amount Paid to the
noncontrolling interest
  Total MEP
Distribution
               (in millions)     
January 28, 2016   February 12, 2016   $8.9   $7.6   $16.5

Omnibus Agreement

We, Midcoast Holdings, MEP and Enbridge are parties to the Omnibus Agreement under which we agreed to, among other things, indemnify MEP for certain matters, including environmental, right-of-way and permit matters. Our obligation to indemnify MEP for these matters is subject to a $500,000 aggregate deductible before MEP is entitled to indemnification. Additionally, there is a $15.0 million aggregate cap on the amounts for which we will indemnify MEP for under the Omnibus Agreement. For the three months ended March 31, 2016, we paid indemnification proceeds to MEP under the Omnibus Agreement of $12.2 million for the acquisition of title to right-of-way assets that were pending at the time of MEP’s initial public offering and associated legal fees.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

10. RELATED PARTY TRANSACTIONS  – (continued)

Financial Support Agreement

At March 31, 2016, we provided $4.9 million of letters of credit outstanding and $23.3 million of guarantees to Midcoast Operating under a Financial Support Agreement with Midcoast Operating. At December 31, 2015, we provided $7.5 million of letters of credit outstanding and $21.7 million of guarantees to Midcoast Operating under this agreement.

Amendment of OLP Limited Partnership Agreement

On July 30, 2015, the partners amended and restated the limited partnership agreement of the OLP, pursuant to which our General Partner will temporarily forego Series EA and ME, collectively, the Series, distributions commencing in the quarter ended June 30, 2015 through the quarter ending March 31, 2016. The General Partner’s capital funding contribution requirements for each of those two Series, commencing in August 2015, will be reduced by the amount of its foregone cash distributions from the respective Series, until the earlier of December 31, 2016 and the date aggregate reductions in capital contributions for such Series are equal to the foregone cash distributions for such Series. To the extent that the General Partner’s portion of capital contributions prior to December 31, 2016 are insufficient to cover the General Partner’s foregone cash distributions for a Series, beginning with the distribution related to the first quarter of 2017 for that Series, we will receive reduced cash distributions by up to 50%, and the General Partner will receive a comparable increase in cash distributions each quarter until the General Partner has received an aggregate amount of contribution reductions and distribution increases equal to the amount of foregone cash distributions.

Joint Funding Arrangement for Eastern Access Projects

The OLP has a series of partnership interests, which we refer to as the EA interests. The EA interests were created to finance the Eastern Access Projects 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. Our General Partner owns 75% of the EA interests, and, except as described above in Amendment of OLP Limited Partnership Agreement, the projects are jointly funded by our General Partner at 75% and us at 25%.

Our General Partner made equity contributions totaling $7.2 million and $36.8 million to the OLP for the three months ended March 31, 2016 and 2015, respectively, to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Distribution to Series EA Interests

The following table presents distributions paid by the OLP during the three months ended March 31, 2016, 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 and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series EA interests.

       
Distribution
Declaration Date
  Distribution
Payment Date
  Amount
Paid to EEP
  Amount Paid to the
noncontrolling interest
  Total Series EA
Distribution
               (in millions)     
January 29, 2016   February 12, 2016   $79.2   $—   $79.2

Joint Funding Arrangement for U.S. Mainline Expansion Projects

The OLP also has a series of partnership interests, which we refer to as 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, except as described above in Amendment of OLP Limited Partnership Agreement, the projects are jointly funded by our General Partner at 75% and us at 25%, under the Mainline Expansion Joint Funding Agreement, which is similar to the Eastern Access Joint Funding Agreement.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

10. RELATED PARTY TRANSACTIONS  – (continued)

Our General Partner has made equity contributions totaling $42.8 million and $162.7 million to the OLP for the three months ended March 31, 2016, and 2015, 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 three months ended March 31, 2016, 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 and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead), L.L.C., the managing general partner of the OLP and the Series ME interests.

       
Distribution
Declaration Date
  Distribution
Payment Date
  Amount
Paid to EEP
  Amount Paid to the
noncontrolling interest
  Total Series ME
Distribution
               (in millions)     
January 29, 2016   February 12, 2016   $40.8   $—   $40.8

11. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

We are subject to federal and state laws and regulations relating to the protection of the environment. Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and we are, at times, subject to environmental cleanup and enforcement actions. We manage this environmental risk through appropriate 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 and Natural Gas 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.

As of March 31, 2016 and December 31, 2015, we had $108.3 million and $95.8 million, respectively, included in “Environmental liabilities,” and $62.4 million and $64.0 million, respectively, included in “Other long-term liabilities,” on our consolidated statements of financial position that we have accrued for costs we have recognized primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids and natural gas 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 perform necessary remediation, 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 appropriate regulatory authorities.

As of March 31, 2016, our cumulative cost estimate for the Line 6B crude oil release remains at $1.2 billion. The liability increased $15.0 million as compared to December 31, 2015 due to an increase in estimated civil penalties under the Clean Water Act of the United States, as described below under Fines and Penalties.

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 March 31, 2016. Our estimates

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

11. COMMITMENTS AND CONTINGENCIES  – (continued)

exclude: (1) amounts we have capitalized, (2) any claims associated with the release that may later become evident, (3) amounts recoverable under insurance, and (4) fines and penalties from other governmental agencies except as described in the 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 material components underlying our cumulative estimated loss for the cleanup, remediation and restoration associated with the Line 6B crude oil release include the following:

 
  (in millions)
Response personnel and equipment   $ 548.6  
Environmental consultants     226.9  
Professional, regulatory and other     447.5  
Total   $ 1,223.0  

For the three months ended March 31, 2016 and 2015, we made payments of $8.4 million and $7.8 million, respectively, for costs associated with the Line 6B crude oil release. As of March 31, 2016 and December 31, 2015, we had a remaining estimated liability of $159.3 million and $149.8 million, respectively.

Fines and Penalties

At March 31, 2016, our total estimated costs related to the Line 6B crude oil release include $62.5 million in fines and penalties. Of this amount, $55.0 million relates to civil penalties under the Clean Water Act of the United States. While no final fine or penalty has been assessed or agreed to date, we believe that, based on the best information available at this time, the $55.0 million represents our estimate of the amount which may be assessed, excluding costs of injunctive relief that may be agreed to with the relevant governmental agencies. Given the complexity of settlement negotiations, which we expect will continue, and the limited information available to assess the matter, we are unable to reasonably estimate the final penalty which might be incurred or to reasonably estimate a range of outcomes at this time. Injunctive relief is likely to include further measures directed toward enhancing spill prevention, leak detection, and emergency response to environmental events, and the cost of compliance with such measures, when combined with any fine or penalty, could be material. We have entered into a tolling agreement with the applicable governmental agencies and discussions with these governmental agencies regarding fines, penalties, and injunctive relief are ongoing.

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 Line 6B crude oil release, excluding costs for fines and penalties.

A majority of the costs incurred for the Line 6B crude oil release are covered by the insurance policy 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 March 31, 2016, costs related to Line 6B exceeded the limits of the coverage available under this insurance policy. As of March 31, 2016, 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. We will

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

11. COMMITMENTS AND CONTINGENCIES  – (continued)

record receivables for additional amounts we claim for recovery pursuant to our insurance policies during the period that we deem realization of the claim for recovery to be probable.

In March 2013, we and Enbridge filed a lawsuit against the insurers of $145.0 million of coverage, as one particular insurer is disputing 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 is 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. The recovery of the remaining $18.0 million is awaiting resolution of that arbitration, which is not scheduled to occur until fourth quarter of 2016. While we believe that those costs are eligible for recovery, there can be no assurance that we will prevail in the arbitration.

Enbridge, together with us and its other affiliates, has renewed its comprehensive property and liability insurance programs, which are effective May 1, 2016 through April 30, 2017, with a liability program aggregate limit of $900.0 million, which includes sudden and accidental pollution liability. In the unlikely 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, MEP, and other Enbridge subsidiaries.

Legal and Regulatory Proceedings

We are a participant in various legal and regulatory proceedings arising in the ordinary course of business. Some of these proceedings are covered, in whole or in part, by insurance. We are also directly, or indirectly, subject to challenges by special interest groups to regulatory approvals and permits for certain of our expansion projects.

A number of governmental agencies and regulators have initiated investigations into the Line 6B crude oil release. Four actions or claims are pending against us and our affiliates in state courts in connection with the Line 6B crude oil release. Based on the current status of these cases, we do not expect the outcome of these actions to be material to our results of operations or financial condition.

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.

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES

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 natural gas, NGLs, condensate, crude oil and fractionation margins. Fractionation margins represent the relative difference between the price we receive from NGL and condensate sales and the corresponding commodity costs of natural gas and natural gas liquids we purchase for processing. Our interest rate risk exposure results from changes in interest rates on our variable rate debt and exists at the corporate level where our variable rate debt obligations are issued. Our exposure to commodity price risk exists within each of our segments. 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.

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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:

   
  March 31,
2016
  December 31,
2015
     (in millions)
Other current assets   $ 101.9     $ 123.9  
Other assets, net     26.2       39.7  
Accounts payable and other(1)     (148.7 )      (130.9 ) 
Other long-term liabilities     (141.0 )      (90.6 ) 
     $ (161.6 )    $ (57.9 ) 

(1) Includes $12.6 million held of cash collateral at December 31, 2015.

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 natural gas, NGL and crude oil sales and purchase contracts and interest rate contracts.

The table below summarizes our derivative balances by counterparty credit quality (any negative amounts represent our net obligations to pay the counterparty).

   
  March 31,
2016
  December 31,
2015
     (in millions)
Counterparty Credit Quality(1)
                 
AAA   $ 0.1     $  
AA(2)     (47.3 )      (12.4 ) 
A     (44.1 )      (10.5 ) 
Lower than A     (70.3 )      (35.0 ) 
     $ (161.6 )    $ (57.9 ) 

(1) As determined by nationally-recognized statistical ratings organizations.
(2) Includes $12.6 million held of cash collateral at December 31, 2015.

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 also decreased. When credit thresholds are met pursuant to the terms of our International Swaps and Derivatives Association, Inc., or 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 March 31, 2016, we did not have any cash collateral on our asset exposures. At December 31, 2015, we held $12.6 million of 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 $198.2 million and $120.1 million relating to our liability exposures pursuant to the margin thresholds in effect at March 31, 2016 and December 31, 2015, 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.

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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 March 31, 2016, we would have been required to provide letters of credit in the amount of $62.9 million related to our positions.

At March 31, 2016 and December 31, 2015, we had credit concentrations in the following industry sectors, as presented below:

   
  March 31,
2016
  December 31,
2015
     (in millions)
United States financial institutions and investment banking entities(1)   $ (95.3 )    $ (30.9 ) 
Non-United States financial institutions     (88.7 )      (51.0 ) 
Other     22.4       24.0  
     $ (161.6 )    $ (57.9 ) 

(1) Includes $12.6 million held of cash collateral at December 31, 2015.

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.

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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   March 31,
2016
  December 31,
2015
  March 31,
2016
  December 31,
2015
          (in millions)
Derivatives designated as hedging instruments:(1)
                                            
Interest rate contracts     Accounts payable and other     $     $     $ (118.3 )    $ (85.2 ) 
Interest rate contracts     Other long-term liabilities                   (126.7 )      (72.3 ) 
                         (245.0 )      (157.5 ) 
Derivatives not designated as hedging instruments:
                                            
Commodity contracts     Other current assets       101.9       123.9              
Commodity contracts     Other assets       26.2       39.7              
Commodity contracts     Accounts payable and other(2)
                  (30.4 )      (33.1 ) 
Commodity contracts     Other long-term liabilities                   (14.3 )      (18.3 ) 
             128.1       163.6       (44.7 )      (51.4 ) 
Total derivative instruments         $ 128.1     $ 163.6     $ (289.7 )    $ (208.9 ) 

(1) Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.
(2) Liability derivatives exclude $12.6 million held of cash collateral at December 31, 2015.

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 March 31, 2016 and December 31, 2015, we also included in AOCI unrecognized losses of approximately $247.6 million and $255.5 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.

During the three months ended March 31, 2015, unrealized commodity hedge gains of $0.6 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $50.0 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at March 31, 2016, will be reclassified from AOCI to earnings during the next 12 months.

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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)          
For the three months ended March 31, 2016
                          
Interest rate contracts   $ (85.6 )      Interest expense     $ (10.1 )      Interest expense     $ (1.9 ) 
Commodity contracts           Commodity Costs       0.1       Commodity Costs        
Total   $ (85.6 )          $ (10.0 )          $ (1.9 ) 
For the three months ended March 31, 2015
                          
Interest rate contracts   $ (145.2 )      Interest expense     $ (5.4 )      Interest expense     $ 28.7  
Commodity contracts     (3.6 )      Commodity Costs       8.4       Commodity Costs       (4.0 ) 
Total   $ (148.8 )          $ 3.0           $ 24.7  

(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
     2016   2015
     (in millions)
Balance at January 1   $ (370.0 )    $ (211.4 ) 
Other comprehensive loss before reclassifications(1)     (87.6 )      (145.1 ) 
Amounts reclassified from AOCI(2)(3)     10.0       (1.0 ) 
Net other comprehensive loss   $ (77.6 )    $ (146.1 ) 
Balance at March 31   $ (447.6 )    $ (357.5 ) 

(1) Excludes NCI gain of $1.3 million reclassified from AOCI at March 31, 2015.
(2) Excludes NCI loss of $2.0 million reclassified from AOCI at March 31, 2015.
(3) For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

Reclassifications from Accumulated Other Comprehensive Income

   
  For the three months
ended March 31,
     2016   2015
     (in millions)
Losses (gains) on cash flow hedges:
                 
Interest Rate Contracts(1)   $ 10.0     $ 5.4  
Commodity Contracts(2)(3)           (6.4 ) 
Total Reclassifications from AOCI   $ 10.0     $ (1.0 ) 

(1) Loss reported within “Interest expense, net” in the consolidated statements of income.
(2) Loss (gain) reported within “Commodity costs” in the consolidated statements of income.
(3) Excludes NCI loss of $2.0 million reclassified from AOCI for the three months ended March 31, 2015.

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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 Consolidated Statements of Income

     
    For the three months
ended March 31,
       2016   2015
      Derivatives Not Designated
        as Hedging Instruments
  Location of Gain or (Loss)
Recognized in Earnings
  Amount of Gain or (Loss)
Recognized in Earnings(1)(2)
          (in millions)
Commodity contracts     Transportation and other services(3)
    $ 0.8     $ 2.7  
Commodity contracts     Commodity sales       (2.4 )      (17.3 ) 
Commodity contracts     Commodity sales – affiliate             (0.2 ) 
Commodity contracts     Commodity costs(4)
      1.8       7.1  
Other contracts     Other income/(expense)             5.0  
Total         $ 0.2     $ (2.7 ) 

(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 $2.5 million and $6.6 million for the three months ended March 31, 2016 and 2015, respectively.
(4) Includes settlement gains of $26.5 million and $25.7 million for the three months ended March 31, 2016 and 2015, 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

         
  As of March 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   $ 128.1     $     $ 128.1     $ (23.2 )    $ 104.9  

         
  As of December 31, 2015
     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(1)
  Net
Amount
     (in millions)
Description:
                                            
Derivatives   $ 163.6     $     $ 163.6     $ (41.5 )    $ 122.1  

(1) Includes $12.6 million of cash collateral held at December 31, 2015.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

Offsetting of Financial Liabilities and Derivative Liabilities

         
  As of March 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   $ (289.7 )    $     $ (289.7 )    $ 23.2     $ (266.5 ) 

         
  As of December 31, 2015
     Gross
Amount of
Recognized
Liabilities(1)
  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(1)
  Net
Amount
     (in millions)
Description:
                                            
Derivatives   $ (221.5 )    $     $ (221.5 )    $ 41.5     $ (180.0 ) 

(1) Includes $12.6 million of cash collateral at December 31, 2015.

Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy our net financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2016 and December 31, 2015. 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.

               
  March 31, 2016   December 31, 2015
     Level 1   Level 2   Level 3   Total   Level 1   Level 2   Level 3   Total
     (in millions)
Interest rate contracts   $     $ (245.0 )    $     $ (245.0 )    $     $ (157.5 )    $     $ (157.5 ) 
Commodity contracts:
                                                                       
Financial           6.0       5.5       11.5             8.4       8.9       17.3  
Physical                 0.9       0.9                   0.6       0.6  
Commodity options                 71.0       71.0                   94.3       94.3  
             (239.0 )      77.4       (161.6 )            (149.1 )      103.8       (45.3 ) 
Cash collateral                                               (12.6 ) 
Total                     $ (161.6 )                      $ (57.9 ) 

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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: (1) quoted prices for assets and liabilities; (2) time value; and (3) 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.

Qualitative Information about Level 3 Fair Value Measurements

Data from pricing services and published indices are used to measure the fair value of our Level 3 derivative instruments on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (natural gas, NGLs, crude and power) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Forward commodity price in isolation has a direct relationship to the fair value of a commodity contract in a long position and an inverse relationship to a commodity contract in a short position. Volatility has a direct relationship to the fair value of an option contract. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. A change to the credit valuation has an inverse relationship to the fair value of our derivative contracts.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

Quantitative Information About Level 3 Fair Value Measurements

             
  Fair Value at
March 31,
2016(2)
  Valuation
Technique
  Unobservable
Input
  Range(1)
          Contract Type   Lowest   Highest   Weighted
Average
  Units
     (in millions)                              
Commodity Contracts – Financial
                                                              
Natural Gas   $ 0.6       Market Approach       Forward Gas Price       1.80       3.27       2.69       MMBtu  
NGLs   $ 4.9       Market Approach       Forward NGL Price       0.17       0.92       0.42       Gal  
Commodity Contracts – Physical
                                                              
Natural Gas   $ (1.8 )      Market Approach       Forward Gas Price       1.53       3.27       2.01       MMBtu  
Crude Oil   $ 0.3       Market Approach       Forward Crude Price       28.29       40.90       38.91       Bbl  
NGLs   $ 2.4       Market Approach       Forward NGL Price       0.17       0.92       0.41       Gal  
Commodity Options
                                                              
Natural Gas, Crude and NGLs   $ 71.0       Option Model       Option Volatility       8 %      100 %      37 %       
Total Fair Value   $ 77.4                                      

(1) Prices are in dollars per Millions of British Thermal Units, or MMBtu, for natural gas; dollars per Gallon, or Gal, for NGLs; and dollars per barrel, or Bbl, for crude oil.
(2) Fair values include credit valuation adjustment losses of approximately $0.2 million.

Quantitative Information About Level 3 Fair Value Measurements

             
  Fair Value at
December 31,
2015(2)
  Valuation
Technique
  Unobservable
Input
  Range(1)
          Contract Type   Lowest   Highest   Weighted
Average
  Units
     (in millions)
Commodity Contracts – Financial                                                               
Natural Gas   $ 0.3       Market Approach       Forward Gas Price       2.27       3.07       2.64       MMBtu  
NGLs     8.6       Market Approach       Forward NGL Price       0.16       0.93       0.41       Gal  
Commodity Contracts – Physical
                                                              
Natural Gas     (2.5 )      Market Approach       Forward Gas Price       2.08       3.44       2.33       MMBtu  
Crude Oil           Market Approach       Forward Crude Price       26.50       38.41       37.29       Bbl  
NGLs     3.1       Market Approach       Forward NGL Price       0.16       1.20       0.40       Gal  
Commodity Options
                                                              
Natural Gas, Crude and NGLs     94.3       Option Model       Option Volatility       13 %      74 %      36 %       
Total Fair Value   $ 103.8                                      

(1) Prices are in dollars per Millions of British Thermal Units, or MMBtu, for natural gas; dollars per Gallon, or Gal, for NGLs; and dollars per barrel, or Bbl, for crude oil.
(2) Fair values include credit valuation adjustment losses of approximately $0.3 million.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

Level 3 Fair Value Reconciliation

The table below provides a reconciliation of changes in the fair value of our Level 3 financial assets and liabilities measured on a recurring basis from January 1, 2016 to March 31, 2016. No transfers of assets between any of the Levels occurred during the period.

       
  Commodity
Financial
Contracts
  Commodity
Physical
Contracts
  Commodity
Options
  Total
     (in millions)
Beginning balance as of January 1, 2016   $ 8.9     $ 0.6     $ 94.3     $ 103.8  
Transfer in (out) of Level 3(1)                        
Gains or losses included in earnings:
                                   
Reported in Commodity sales           (6.7 )            (6.7 ) 
Reported in Commodity costs     0.4       8.5       (1.5 )      7.4  
Gains or losses included in other comprehensive income:
                                   
Purchases, issuances, sales and settlements:
                                   
Purchases                        
Sales                        
Settlements(2)     (3.8 )      (1.5 )      (21.8 )      (27.1 ) 
Ending balance as March 31, 2016   $ 5.5     $ 0.9     $ 71.0     $ 77.4  
Amounts reported in Commodity sales   $     $ (2.4 )    $     $ (2.4 ) 
Amount of changes in net assets attributable to the change in derivative gains or losses related to assets and liabilities still held at the reporting date:
                                   
Reported in Commodity sales   $     $ (2.7 )    $     $ (2.7 ) 
Reported in Commodity costs   $ 0.4     $ 4.8     $ (2.5 )      2.7  

(1) Our policy is to recognize transfers as of the last day of the reporting period.
(2) Settlements represent the realized portion of forward contracts.

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ENBRIDGE ENERGY PARTNERS, L.P.
 
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

12. DERIVATIVE FINANCIAL INSTRUMENTS AND HEDGING ACTIVITIES  – (continued)

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 and physical contracts at March 31, 2016 and December 31, 2015.

               
  At March 31, 2016   At December 31, 2015
  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 2016
                                                              
Swaps
                                                                       
Receive variable/pay fixed     Natural Gas       16,287     $ 2.43     $ 3.48     $     $     $     $  
       NGL       1,570,750     $ 23.30     $ 25.39     $ 1.8     $ (5.1 )    $ 0.2     $ (8.4 ) 
       Crude Oil       464,000     $ 40.65     $ 65.19     $ 0.1     $ (11.5 )    $     $ (17.5 ) 
Receive fixed/pay variable     NGL       1,894,000     $ 27.74     $ 22.68     $ 11.0     $ (1.4 )    $ 18.3     $ (0.2 ) 
       Crude Oil       970,575     $ 58.65     $ 41.08     $ 17.6     $ (0.6 )    $ 25.4     $  
Receive variable/pay variable     Natural Gas       7,355,000     $ 2.47     $ 2.47     $ 0.2     $ (0.2 )    $ 0.1     $ (0.1 ) 
Physical Contracts
                                                                       
Receive variable/pay fixed     NGL       890,000     $ 17.94     $ 16.02     $ 1.8     $ (0.1 )    $     $ (0.2 ) 
       Crude Oil           $     $     $     $     $     $ (0.2 ) 
Receive fixed/pay variable     NGL       869,166     $ 22.46     $ 24.95     $ 0.1     $ (2.3 )    $ 1.9     $ (0.2 ) 
Receive variable/pay variable     Natural Gas       118,233,634     $ 1.94     $ 1.96     $     $ (2.1 )    $     $ (2.8 ) 
       NGL       8,400,616     $ 16.85     $ 16.51     $ 3.7     $ (0.8 )    $ 4.0     $ (2.4 ) 
       Crude Oil       681,040     $ 38.84     $ 38.38     $ 0.7     $ (0.4 )    $ 0.7     $ (0.5 ) 
Portion of contracts maturing in 2017
                                                              
Swaps
                                                                       
Receive variable/pay fixed     Natural Gas       76,530     $ 2.49     $ 2.97     $     $     $     $  
       NGL       757,500     $ 16.63     $ 21.05     $ 0.1     $ (3.5 )    $     $ (4.5 ) 
       Crude Oil       547,500     $ 44.92     $ 66.72     $     $ (11.8 )    $     $ (10.9 ) 
Receive fixed/pay variable     NGL       757,500     $ 19.19     $ 16.63     $ 2.2     $ (0.3 )    $ 3.3     $ (0.1 ) 
       Crude Oil       638,750     $ 63.63     $ 44.92     $ 11.9     $     $ 10.9     $  
Receive variable/pay variable     Natural Gas       12,550,000     $ 2.75     $ 2.70     $ 0.8     $ (0.2 )    $ 0.5     $ (0.2 ) 
Physical Contracts
                                                                       
Receive fixed/pay variable     NGL       595     $ 22.37     $ 21.17     $     $     $     $  
Receive variable/pay variable     Natural Gas       3,987,810     $ 2.78     $ 2.75     $ 0.1     $     $ 0.1     $  
       NGL       186,500     $ 23.33     $ 23.40     $     $     $     $  
Portion of contracts maturing in 2018