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Table of Contents

 

 

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 June 30, 2014

OR

 

¨ 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

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  ¨

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  ¨

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   ¨
Non-Accelerated Filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company     ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

The registrant had 254,208,428 Class A common units outstanding as of August 1, 2014.

 

 

 


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 and six month periods ended June 30, 2014 and 2013

    1   
 

Consolidated Statements of Comprehensive Income for the three and six month periods ended June  30, 2014 and 2013

    2   
 

Consolidated Statements of Cash Flows for the six month periods ended June 30, 2014 and 2013

    3   
 

Consolidated Statements of Financial Position as of June 30, 2014 and December 31, 2013

    4   
 

Notes to the Consolidated Financial Statements

    5   

Item 2.

 

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

    44   

Item 3.

 

Quantitative and Qualitative Disclosures About Market Risk

    78   

Item 4.

 

Controls and Procedures

    82   
 

PART II - OTHER INFORMATION

 

Item 1.

 

Legal Proceedings

    82   

Item 1A.

 

Risk Factors

    82   

Item 6.

 

Exhibits

    82   

Signatures

      83   

Exhibits

    84   

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.”

This Quarterly Report on Form 10-Q includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “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 the Partnership’s ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include: (1) changes in the demand for, 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; and (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.

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, 2013 and our subsequently filed Quarterly Reports on form 10-Q, which is available to the public over the Internet at the U.S. Securities and Exchange Commission’s, or SEC’s, website (www.sec.gov) and at our website (www.enbridgepartners.com).

 

i


Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

 

     For the three month
period ended June 30,
     For the six month
period ended June 30,
 
     2014      2013      2014      2013  
     (unaudited; in millions, except per unit amounts)  

Operating revenue (Note 10)

   $ 1,785.1      $ 1,603.9      $ 3,789.6      $ 3,226.3  

Operating revenue—affiliate (Note 8)

     86.0        68.8        161.1        139.4  
  

 

 

    

 

 

    

 

 

    

 

 

 
     1,871.1        1,672.7        3,950.7        3,365.7  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating expenses:

           

Cost of natural gas (Notes 4 and 10)

     1,221.4        1,081.0        2,679.9        2,234.4  

Cost of natural gas—affiliate (Note 8)

     38.4        34.5        68.6        72.5  

Environmental costs, net of recoveries (Note 9)

     38.2        5.2        43.2        183.7  

Operating and administrative

     107.3        113.3        203.9        195.3  

Operating and administrative—affiliate (Note 8)

     117.3        104.7        237.7        217.6  

Power (Note 10)

     54.2        29.2        104.6        62.8  

Depreciation and amortization

     113.4        95.8        217.2        188.0  
  

 

 

    

 

 

    

 

 

    

 

 

 
     1,690.2        1,463.7        3,555.1        3,154.3  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating income

     180.9        209.0        395.6        211.4  

Interest expense, net (Notes 6 and 10)

     80.2        79.5        157.1        155.9  

Allowance for equity used during construction (Note 13)

     12.6        8.1        33.3        15.9  

Other income

     1.2        0.3        0.4        0.6  
  

 

 

    

 

 

    

 

 

    

 

 

 

Income before income tax expense

     114.5        137.9        272.2        72.0  

Income tax expense (Note 11)

     2.0        14.2        4.0        16.0  
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income

     112.5        123.7        268.2        56.0  

Less: Net income attributable to:

           

Noncontrolling interest (Note 8)

     42.4        18.4        78.7        34.0  

Series 1 preferred unit distributions (Note 7)

     22.5        13.1        45.0        13.1  

Accretion of discount on Series 1 preferred units (Note 7)

     3.7        2.3        7.3        2.3  
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.

   $ 43.9      $ 89.9      $ 137.2      $ 6.6  
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income (loss) allocable to limited partner interests

   $ 5.0      $ 56.7      $ 63.9      $ (56.2
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income (loss) per limited partner unit (basic) (Note 2)

   $ 0.02      $ 0.18      $ 0.19      $ (0.18
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted average limited partner units outstanding (basic)

     327.6        314.8        327.0        311.0  
  

 

 

    

 

 

    

 

 

    

 

 

 

Net income (loss) per limited partner unit (diluted) (Note 2)

   $ 0.02      $ 0.18      $ 0.19      $ (0.18
  

 

 

    

 

 

    

 

 

    

 

 

 

Weighted average limited partner units outstanding (diluted)

     327.6        314.8        327.0        311.0  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

 

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

 

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Table of Contents

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

     For the three month
period ended
June 30,
     For the six month
period ended
June 30,
 
     2014     2013      2014     2013  
     (unaudited; in millions)  

Net income

   $ 112.5     $ 123.7      $ 268.2     $ 56.0  

Other comprehensive income (loss), net of tax expense of $0.0 million $0.1 million, $0.0 million and $0.1 million, respectively (Note 10)

     (66.0     162.0        (136.1     191.7  
  

 

 

   

 

 

    

 

 

   

 

 

 

Comprehensive income

     46.5       285.7        132.1       247.7  

Less: Comprehensive income attributable to:

         

Noncontrolling interest (Note 8)

     42.4       18.4        78.7       34.0  

Series 1 preferred unit distributions (Note 7)

     22.5       13.1        45.0       13.1  

Accretion of discount on Series 1 preferred units (Note 7)

     3.7       2.3        7.3       2.3  

Other comprehensive income (loss) attributed to noncontrolling interest

     (0.3     —          (0.3     —    
  

 

 

   

 

 

    

 

 

   

 

 

 

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

   $ (21.8   $ 251.9      $ 1.4     $ 198.3  
  

 

 

   

 

 

    

 

 

   

 

 

 

 

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

 

2


Table of Contents

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     For the six month
period ended June 30,
 
         2014             2013      
     (unaudited; in millions)  

Cash provided by operating activities:

    

Net income

   $ 268.2     $ 56.0  

Adjustments to reconcile net income to net cash provided by operating activities:

    

Depreciation and amortization (Note 5)

     217.2       188.0  

Derivative fair value net losses (gains) (Note 10)

     24.7       (22.3

Inventory market price adjustments (Note 4)

     3.3       2.5  

Environmental costs, net of recoveries (Note 9)

     38.0       179.7  

Distributions from investments in joint ventures (Note 8)

     1.0       —    

Equity earnings from investments in joint ventures (Note 8)

     (1.0     —    

Deferred income taxes (Note 11)

     1.3       13.2  

State income taxes

     1.8       7.4  

Allowance for equity used during construction (Note 13)

     (33.3     (15.9

Other

     (0.8     7.3  

Changes in operating assets and liabilities, net of acquisitions:

    

Receivables, trade and other

     9.1       60.1  

Due from General Partner and affiliates

     5.3       4.5  

Accrued receivables

     51.8       276.3  

Inventory (Note 4)

     (75.7     (95.1

Current and long-term other assets (Note 10)

     (16.5     (19.1

Due to General Partner and affiliates

     (6.0     18.4  

Accounts payable and other (Notes 3 and 10)

     (63.8     (40.3

Environmental liabilities (Note 9)

     (62.9     (32.7

Accrued purchases

     (3.2     (95.3

Interest payable

     1.4       4.1  

Property and other taxes payable

     (1.6     (14.0

Settlement of interest rate derivatives (Note 10)

     1.3       (5.3
  

 

 

   

 

 

 

Net cash provided by operating activities

     359.6       477.5  
  

 

 

   

 

 

 

Cash used in investing activities:

    

Additions to property, plant and equipment (Notes 5 and 14)

     (1,309.0     (859.7

Changes in restricted cash (Note 8)

     36.1       (3.4

Investments in joint ventures (Note 8)

     (28.1     (126.7

Distributions from investments in joint ventures in excess of cumulative earnings

     17.7       —    

Other

     (3.7     (4.0
  

 

 

   

 

 

 

Net cash used in investing activities

     (1,287.0     (993.8
  

 

 

   

 

 

 

Cash provided by financing activities:

    

Net proceeds from Series 1 preferred unit issuance (Note 7)

     —         1,200.0  

Net proceeds from unit issuances (Note 7)

     —         278.7  

Distributions to partners (Note 7)

     (356.9     (353.3

Repayments to General Partner (Note 8)

     (6.0     (6.0

Repayments of long-term debt (Note 6)

     —         (200.0

Net borrowings under credit facility (Note 6)

     140.0       —    

Net commercial paper borrowings (repayments) (Note 6)

     765.0       (724.7

Contributions from noncontrolling interest (Notes 7 and 8)

     612.9       149.7  

Distributions to noncontrolling interest (Notes 7 and 8)

     (42.5     (28.7
  

 

 

   

 

 

 

Net cash provided by financing activities

     1,112.5       315.7  
  

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     185.1       (200.6

Cash and cash equivalents at beginning of year

     164.8       227.9  
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 349.9     $ 27.3  
  

 

 

   

 

 

 

 

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

 

3


Table of Contents

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 

     June 30,
2014
    December 31,
2013
 
     (unaudited; in millions)  
ASSETS     

Current assets:

    

Cash and cash equivalents (Note 3)

   $ 349.9     $ 164.8  

Restricted cash (Note 8)

     33.3       69.4  

Receivables, trade and other, net of allowance for doubtful accounts of $0.5 million in 2014 and 2013 (Note 9)

     51.7       49.4  

Due from General Partner and affiliates

     36.5       40.5  

Accrued receivables

     147.0       210.2  

Inventory (Note 4)

     164.9       94.9  

Other current assets (Note 10)

     58.7       47.6  
  

 

 

   

 

 

 
     842.0       676.8  

Property, plant and equipment, net (Note 5)

     14,207.1       13,176.8  

Goodwill

     246.7       246.7  

Intangibles, net

     257.7       263.2  

Other assets, net (Note 10)

     509.9       538.0  
  

 

 

   

 

 

 
   $ 16,063.4     $ 14,901.5  
  

 

 

   

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL     

Current liabilities:

    

Due to General Partner and affiliates (Note 8)

   $ 118.1     $ 121.4  

Accounts payable and other (Notes 3, 10 and 13)

     710.9       822.0  

Environmental liabilities (Note 9)

     187.7       233.7  

Accrued purchases

     457.4       465.6  

Interest payable

     69.4       68.0  

Property and other taxes payable (Note 11)

     68.8       70.7  

Note payable to General Partner (Note 8)

     12.0       12.0  

Current maturities of long-term debt (Note 6)

     200.0       200.0  
  

 

 

   

 

 

 
     1,824.3       1,993.4  

Long-term debt (Note 6)

     5,682.7       4,777.4  

Loans from General Partner and affiliate (Note 8)

     300.0       306.0  

Due to General Partner and affiliates (Note 8)

     103.3       58.2  

Deferred income tax liability (Note 11)

     18.7       17.4  

Other long-term liabilities (Notes 9 and 10)

     136.4       51.7  
  

 

 

   

 

 

 

Total liabilities

     8,065.4       7,204.1  
  

 

 

   

 

 

 

Commitments and contingencies (Note 9)

    

Partners’ capital: (Notes 7 and 8)

    

Series 1 preferred units (48,000,000 at June 30, 2014 and December 31, 2013)

     1,168.0       1,160.7  

Class A common units (254,208,428 at June 30, 2014 and December 31, 2013)

     2,755.5       2,979.0  

Class B common units (7,825,500 at June 30, 2014 and December 31, 2013)

     58.5       65.3  

i-units (66,196,781 and 63,743,099 at June 30, 2014 and December 31, 2013, respectively)

     1,305.1       1,291.9  

General Partner

     298.9       301.5  

Accumulated other comprehensive income (loss) (Note 10)

     (212.4     (76.6
  

 

 

   

 

 

 

Total Enbridge Energy Partners, L.P. partners’ capital

     5,373.6       5,721.8  

Noncontrolling interest (Note 8)

     2,624.4       1,975.6  
  

 

 

   

 

 

 

Total partners’ capital

     7,998.0       7,697.4  
  

 

 

   

 

 

 
   $ 16,063.4     $ 14,901.5  
  

 

 

   

 

 

 

 

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

 

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Table of Contents

ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted 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, they 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 June 30, 2014, our results of operations for the three and six month periods ended June 30, 2014 and 2013, and our cash flows for the six month periods ended June 30, 2014 and 2013. We derived our consolidated statement of financial position as of December 31, 2013, from the audited financial statements included in our Annual Report on Form 10 K for the fiscal year ended December 31, 2013. Our results of operations for the six month period ended June 30, 2014, 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, 2013.

Comparative Amounts

During the first quarter of 2014, we changed our reporting segments. The Marketing segment was combined with the Natural Gas segment to form one new segment named “Natural Gas.” There was no change to the Liquids segment.

This change was a result of our reorganization resulting from Midcoast Energy Partner, L.P.’s, or MEP’s, initial public offering, or IPO, of its Class A common units representing limited partnership interests, which prompted management to reassess the presentation of EEP’s reportable segments considering the financial information available and evaluated regularly by our Chief Operating Decision Maker. Our new segment reporting is consistent with how management makes resource allocation decisions, evaluates performance, and furthers the achievement of our long-term objectives. Financial information for the prior periods has been restated to reflect the change in reporting segments.

Additionally, we have reclassified certain prior period affiliate amounts related to operating revenue, the cost of natural gas, and operating and administrative expenses to conform to the current period presentation. These reclassifications did not impact net income.

After filing our Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2014, we determined that the beneficial conversion feature of our preferred units in the amount of $47.7 million was incorrectly presented in the statement of financial position as of March 31, 2014, and in the significant changes in partners’ capital table in footnote 7, “Partners’ Capital,” for the three month period ended March 31, 2014. The presentation error resulted in an understatement of the Series 1 Preferred Interests and an overstatement of the General and Limited Partner Interests by $47.7 million at March 31, 2014. We have concluded that this error is immaterial to the prior interim financial statements for the quarterly prior ended March 31, 2014. This error did not affect our total partners’ capital at March 31, 2014, or our cash flow or earnings for the three month period ended March 31, 2014. We have corrected these items for the three and six month periods ended June 30, 2014.

 

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Table of Contents

2. NET INCOME PER LIMITED PARTNER UNIT

We allocate our net income among our Series 1 Preferred Units, or Preferred Units, our General Partner, and our limited partners 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 and limited partner interests to our General Partner and our limited partners according to the distribution formula for available cash as set forth in our partnership agreement. We also allocate any earnings in excess of distributions to our General Partner and limited partners 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 based on their sharing of losses of 2% and 98%, respectively, as set forth in our partnership agreement. Historically we have made the distributions in excess of earnings as follows:

 

Distribution Targets

  

Portion of Quarterly
Distribution Per Unit

   Percentage Distributed to
General Partner
  Percentage Distributed
to Limited partners
 

Minimum Quarterly Distribution

   Up to $0.295    2 %     98 

First Target Distribution

   > $0.295 to $0.35    15 %     85 

Second Target Distribution

   > $0.35 to $0.495    25 %     75 

Over Second Target Distribution

   In excess of $0.495    50 %     50 

Equity Restructuring Transaction

Effective July 1, 2014, the General Partner entered into an equity restructuring transaction, or Equity Restructuring, with us in which the General Partner irrevocably waived its right to receive cash distributions and allocations of items of income, gain, deduction and loss in excess of 2% in respect of its general partner interest in the incentive distribution rights, or Previous IDRs, in exchange for the issuance to a wholly-owned subsidiary of the General Partner of (i) 66.1 million units of a new class of Partnership units designated as Class D Units, and (ii) 1,000 units of a new class of Partnership units designated as Incentive Distribution Units. The irrevocable waiver is effective with respect to the calendar quarter ending on June 30, 2014, and each calendar quarter thereafter.

The Class D Units entitle the holder thereof to receive quarterly distributions equal to the distribution paid on our common units. The Class D Units are convertible on a one-for-one basis into our Class A common units any time after the fifth anniversary of issuance, or July 1, 2019, at the holder’s option. We may redeem Class D Units in whole or in part after the 30-year anniversary of issuance, or July 1, 2044, at our option for either a cash amount equal to the notional value per unit or newly issued Class A common units with an aggregate market value at redemption equal to 105% of the aggregate notional value of the Class D Units being redeemed. The Class D Units have a notional value of $31.35 per unit, which was the closing price of our Class A common units on June 17, 2014, and have the same voting rights as the Class A units. In the event of a liquidation event (or any merger or other extraordinary transaction), the Class D Units will entitle the holder thereof to a preference in liquidation equal to 20% of the notional value, with such preference being increased by an additional 20% on each anniversary of issuance, resulting in a liquidation preference equal to 100% of the notional value on and after July 1, 2018.

The Incentive Distribution Units entitle the holder thereof to receive 23% of the incremental distributions we pay in excess of $0.5435 per common unit and Class D Unit per quarter. In the event of any decrease in the Class A common unit distribution below the current quarterly distribution level of $0.5435 per unit in any quarter during the five years commencing with the fourth quarter of 2014, the distribution we pay on the Class D Units will be adjusted to the amount that we would have paid in respect of the Previous IDRs had the Equity Restructuring not occurred. In addition, the third quarter 2014 distribution on the Class D Units will be reduced so that the aggregate distributions we pay in calendar year 2014 with respect to the Previous IDRs, the Class D Units and the Incentive Distribution Units will not exceed the distribution that we would have paid in calendar year 2014 in respect to the Previous IDRs had the Equity Restructuring not occurred.

 

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

 

     For the three month
period ended
June 30,
    For the six month
period ended
June 30,
 
     2014     2013     2014     2013  
     (in millions, except per unit amounts)  

Net income

   $ 112.5     $ 123.7     $ 268.2     $ 56.0  

Less Net income attributable to:

        

Noncontrolling interest

     (42.4     (18.4     (78.7     (34.0

Series 1 preferred unit distributions

     (22.5     (13.1     (45.0     (13.1

Accretion of discount on Series 1 preferred units

     (3.7     (2.3     (7.3     (2.3
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to general and limited partner interests in Enbridge Energy Partners, L.P.

     43.9       89.9       137.2       6.6  

Less distributions:

        

Incentive distributions to our General Partner

     (38.0     (32.0     (71.2     (63.9

Distributed earnings allocated to our General Partner

     (4.5     (3.5     (8.1     (7.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Total distributed earnings to our General Partner

     (42.5     (35.5     (79.3     (70.9

Total distributed earnings to our limited partners

     (182.2     (171.3     (359.9     (342.1
  

 

 

   

 

 

   

 

 

   

 

 

 

Total distributed earnings

     (224.7     (206.8     (439.2     (413.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Overdistributed earnings

   $ (180.8   $ (116.9   $ (302.0   $ (406.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average limited partner units outstanding

     327.6       314.8       327.0       311.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

Basic and diluted earnings per unit:

        

Distributed earnings per limited partner unit (1)

   $ 0.56     $ 0.54     $ 1.10     $ 1.10  

Overdistributed earnings per limited partner unit (2)

     (0.54     (0.36     (0.91     (1.28
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss) per limited partner unit (basic and diluted) (3)

   $ 0.02     $ 0.18     $ 0.19     $ (0.18
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Represents the total distributed earnings to limited partners divided by the weighted average number of limited partner interests outstanding for the period.

(2) 

Represents the limited partners’ share (98%) of distributions in excess of earnings divided by the weighted average number of limited partner interests outstanding for the period and overdistributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

(3) 

For the three and six month periods ended June 30, 2014, 43,201,310 anti-dilutive Preferred Units were excluded from the if-converted method of calculating diluted earnings per unit.

3. 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 $16.1 million at June 30, 2014, and $24.0 million at December 31, 2013, are included in “Accounts payable and other” on our consolidated statements of financial position.

4. INVENTORY

Our inventory is comprised of the following:

 

     June 30,
2014
     December 31,
2013
 
     (in millions)  

Materials and supplies

   $ 2.1      $ 2.1  

Crude oil inventory

     24.4        18.0  

Natural gas and NGL inventory

     138.4        74.8  
  

 

 

    

 

 

 
   $ 164.9      $ 94.9  
  

 

 

    

 

 

 

 

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The “Cost of natural gas and natural gas liquids” on our consolidated statements of income includes charges totaling $1.5 million and $3.3 million, and $1.7 million and $2.5 million for the three and six month periods ended June 30, 2014 and 2013, respectively, that we recorded to reduce the cost basis of our inventory of natural gas and natural gas liquids, or NGLs, to reflect the current market value.

5. PROPERTY, PLANT AND EQUIPMENT

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

 

     June 30,
2014
    December 31,
2013
 
     (in millions)  

Land

   $ 45.4     $ 43.6  

Rights-of-way

     770.9       666.2  

Pipelines

     9,302.2       8,035.8  

Pumping equipment, buildings and tanks

     2,702.7       2,233.0  

Compressors, meters and other operating equipment

     2,045.3       1,989.8  

Vehicles, office furniture and equipment

     353.2       322.0  

Processing and treating plants

     513.8       514.4  

Construction in progress

     1,379.0       2,077.7  
  

 

 

   

 

 

 

Total property, plant and equipment

     17,112.5       15,882.5  

Accumulated depreciation

     (2,905.4     (2,705.7
  

 

 

   

 

 

 

Property, plant and equipment, net

   $ 14,207.1     $ 13,176.8  
  

 

 

   

 

 

 

In the first quarter of 2014, we recorded asset retirement obligations, or AROs, of $100.6 million. Of that amount, $60.0 million is related to Line 6B and is recorded in “Accounts payable and other” with an offset to “Property, plant and equipment, net” in our statement of financial position and $40.6 million is related to Line 3, and is recorded in “Other long-term liabilities” with an offset to “Property, plant and equipment, net” in our consolidated statements of financial position. Both of these pipelines are part of our Lakehead system and the AROs are related to the decommissioning of these pipelines as we are completing Line 6B replacement work in 2014 and have recently announced the Line 3 replacement with an estimated in-service date of late 2017. The associated ARO is a component of the pipelines category of property, plant and equipment, net. We record ARO at fair value in the period in which they can be reasonably determined. Fair value is determined based on expected future cash flows and estimated retirement periods, as well as discount and inflation rates.

6. DEBT

Credit Facilities

We have a committed senior unsecured revolving credit facility, which we refer to as the Credit Facility, that permits aggregate borrowings of up to, at any one time outstanding, $1.975 billion. The maturity date on the Credit Facility is September 26, 2018.

We also have a credit agreement, which we refer to as the 364-Day Credit Facility, that provided aggregate lending commitments of up to $1.2 billion: (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.

On July 3, 2014, we amended our 364-Day Credit Facility to extend the revolving credit termination date to July 3, 2015, and to decrease aggregate commitments under the facility by $550.0 million. After these changes, our 364-day Credit Facility now provides to us aggregate lending commitments of $650.0 million.

We refer to our Credit Facility and our 364-Day Credit Facility as the Credit Facilities, which provided an aggregate amount of approximately $3.2 billion of bank credit, as of June 30, 2014, which we use to fund our general activities and working capital needs.

 

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The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. 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. Taking that policy into account, at June 30, 2014, we could borrow approximately $1.9 billion under the terms of our Credit Facilities, determined as follows:

 

     (in millions)  

Total credit available under Credit Facilities

   $ 3,175.0  

Less: Amounts outstanding under Credit Facilities

     —    

Principal amount of commercial paper outstanding

     1,065.0  

Letters of credit outstanding

     160.3  
  

 

 

 

Total amount we could borrow at June 30, 2014

   $ 1,949.7  
  

 

 

 

Individual London Inter-Bank Offered Rate, or LIBOR rate, borrowings under the terms of our Credit Facilities may be renewed as LIBOR rate borrowings or as base rate borrowings at the end of each LIBOR rate interest period, which is typically a period of three months or less. These renewals do not constitute new borrowings under the Credit Facilities and do not require any cash repayments or prepayments. For the three and six month periods ended June 30, 2014 and 2013, we did not have any LIBOR rate borrowings or base rate borrowings.

As of June 30, 2014, we were in compliance with the terms of all of our financial covenants under the Credit Facilities.

On February 3, 2014, we entered into an uncommitted letter of credit arrangement, pursuant to which the bank may, on a discretionary basis and with no commitment, agree to issue standby letters of credit upon our request in an aggregate amount not to exceed $200.0 million. While the letter of credit arrangement is uncommitted and issuance of letters of credit is at the bank’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.

Commercial Paper

We have a commercial paper program that 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. At June 30, 2014, we had approximately $1.1 billion in principal amount of commercial paper outstanding at a weighted average interest rate of 0.33%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net borrowings of approximately $765.0 million during the six month period ended June 30, 2014, which includes gross borrowings of $4.4 billion and gross repayments of $3.6 billion. At December 31, 2013, we had $300.0 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.37%, excluding the effect of our interest rate hedging activities. 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.

We have the ability and intent to refinance all of our commercial paper obligations on a long-term basis through borrowings under our Credit Facilities. Accordingly, such amounts have been classified as “Long-term debt” in our accompanying consolidated statements of financial position.

Senior Notes

All of our senior notes represent our unsecured obligations that rank equally in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. Our senior notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables of our

 

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subsidiaries and the $200.0 million of senior notes issued by Enbridge Energy, Limited Partnership, or the OLP, which we refer to as the OLP Notes. The borrowings under our senior notes are non-recourse to our General Partner and Enbridge Management. All of our senior notes either pay or accrue interest semi-annually and have varying maturities and terms.

The OLP, our operating subsidiary that owns the Lakehead system, has $200.0 million of senior notes outstanding representing unsecured obligations that are structurally senior to our senior notes. The OLP Notes consist of $100.0 million of 7.000% senior notes due in 2018 and $100.0 million of 7.125% senior notes due in 2028. All of the OLP Notes pay interest semi-annually.

Junior Subordinated Notes

The $400.0 million in principal amount of our fixed/floating rate, junior subordinated notes due 2067, which we refer to as the Junior Notes, represent our unsecured obligations that are subordinate in right of payment to all of our existing and future senior indebtedness.

The Junior Notes do not restrict our ability to incur additional indebtedness. However, with limited exceptions, during any period we elect to defer interest payments on the Junior Notes, we cannot make cash distribution payments or liquidate any of our equity securities, nor can we or our subsidiaries make any principal and interest payments for any debt that ranks equally with or junior to the Junior Notes.

MEP Credit Agreement

On November 13, 2013, MEP, Midcoast Operating L.P., or Midcoast Operating, and their material domestic subsidiaries, entered into a senior revolving credit facility, which we refer to as the MEP Credit Agreement, that permits aggregate borrowings of up to, at any one time outstanding, $850.0 million. The original term of the MEP Credit Agreement is three years with an initial maturity date of November 2016, subject to four one-year requests for extensions. At June 30, 2014, MEP had $475.0 million in outstanding borrowings under the MEP Credit Agreement at a weighted average interest rate of 1.9%. Under the MEP Credit Agreement, MEP had net borrowings of approximately $140.0 million during the six month period ended June 30, 2014, which includes gross borrowings of $3.4 billion and gross repayments of $3.3 billion. As of June 30, 2014, MEP was in compliance with the terms of its financial covenants.

Interest Cost

Our interest cost for the three and six month periods ended June 30, 2014 and 2013 is comprised of the following:

 

     For the three month
period ended June 30,
    For the six month
period ended June 30,
 
         2014             2013             2014             2013      
     (in millions)  

Interest expense

   $ 80.2     $ 79.5     $ 157.1     $ 155.9  

Interest capitalized

     10.2       12.1       24.1       26.4  
  

 

 

   

 

 

   

 

 

   

 

 

 

Interest cost incurred

   $ 90.4     $ 91.6     $ 181.2     $ 182.3  
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average interest rate

     6.2     6.1     6.4     6.1

Fair Value of Debt Obligations

The table below presents the carrying amounts, net of related unamortized discount, and approximate fair values of our debt obligations. The carrying amounts of our outstanding commercial paper and borrowings under our Credit Facilities and prior credit facilities approximate their fair values at June 30, 2014 and December 31, 2013, respectively, due to the short-term nature and frequent repricing of the amounts outstanding under these

 

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obligations. The fair value of our outstanding commercial paper and borrowings under our Credit Facilities are included with our long-term debt obligations below since we have the ability and the intent to refinance the amounts outstanding on a long-term basis. The approximate fair values of our long-term debt obligations are determined 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.

 

     June 30, 2014      December 31, 2013  
     Carrying
Amount
     Fair
Value
     Carrying
Amount
     Fair
Value
 
     (in millions)  

Commercial Paper

   $ 1,065.0      $ 1,065.0      $ 300.0      $ 300.0  

MEP Credit Agreement

     475.0        475.0        335.0        335.0  

5.350% Senior Notes due 2014

     200.0        204.8        200.0        210.0  

5.875% Senior Notes due 2016

     299.9        333.9        299.9        335.0  

7.000% Senior Notes due 2018

     99.9        120.4        99.9        118.6  

6.500% Senior Notes due 2018

     399.2        469.5        399.1        464.5  

9.875% Senior Notes due 2019

     500.0        670.4        500.0        663.9  

5.200% Senior Notes due 2020

     499.9        565.9        499.9        544.8  

4.200% Senior Notes due 2021

     599.1        635.8        599.1        599.7  

7.125% Senior Notes due 2028

     99.8        133.8        99.8        121.9  

5.950% Senior Notes due 2033

     199.8        241.8        199.8        214.4  

6.300% Senior Notes due 2034

     99.8        125.4        99.8        110.9  

7.500% Senior Notes due 2038

     399.1        571.0        399.0        503.4  

5.500% Senior Notes due 2040

     546.4        611.9        546.4        531.0  

8.050% Junior subordinated notes due 2067

     399.8        452.8        399.7        446.4  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 5,882.7      $ 6,677.4      $ 4,977.4      $ 5,499.5  
  

 

 

    

 

 

    

 

 

    

 

 

 

7. 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 six month period ended June 30, 2014.

 

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)  

April 30, 2014

    May 8, 2014        May 15, 2014      $ 0.5435     $ 214.5     $ 35.3      $ 0.7      $ 178.5  

January 30, 2014

    February 7, 2014        February 14, 2014      $ 0.5435     $ 213.7     $ 34.6      $ 0.7      $ 178.4  

 

(1) 

We issued 2,453,682 i-units to Enbridge Management, the sole owner of our i-units, during 2014 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.

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 interest in our consolidated subsidiary, OLP, for the six month periods ended June 30, 2014 and 2013. The noncontrolling interest in the OLP arises from the joint

 

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funding arrangements with our General Partner and its affiliate to finance: (1) construction of the United States portion of the Alberta Clipper crude oil pipeline and related facilities, which we refer to as the Alberta Clipper Pipeline; (2) expansion of our Lakehead system to transport crude oil to destinations in the Midwest United States, which we refer to as the Eastern Access Projects; and (3) further expansion of our Lakehead system to transport crude oil between Neche, North Dakota and Superior, Wisconsin, which we refer to as the Mainline Expansion Projects.

 

     For the six month
period ended June 30,
 
           2014                 2013        
     (in millions)  

Series 1 Preferred interests

    

Beginning balance

   $ 1,160.7     $ —    

Proceeds from issuance of preferred units

     —         1,200.0  

Net income

     45.0       13.1  

Accretion of discount on preferred units

     7.3       2.3  

Distribution payable

     (45.0     (13.1

Beneficial conversion feature of preferred units

     —         (47.7
  

 

 

   

 

 

 

Ending balance

   $ 1,168.0     $ 1,154.6  
  

 

 

   

 

 

 

General and limited partner interests

    

Beginning balance

   $ 4,637.7     $ 4,774.9  

Proceeds from issuance of partnership interests, net of costs

     —         278.7  

Net income

     137.2       6.6  

Distributions

     (356.9     (353.3

Beneficial conversion feature of preferred units

     —         47.7  
  

 

 

   

 

 

 

Ending balance

   $ 4,418.0     $ 4,754.6  
  

 

 

   

 

 

 

Accumulated other comprehensive loss

    

Beginning balance

   $ (76.6   $ (320.5

Changes in fair value of derivative financial instruments reclassified to earnings

     16.6       16.5  

Changes in fair value of derivative financial instruments recognized in other comprehensive income (loss)

     (152.4     175.2  
  

 

 

   

 

 

 

Ending balance

   $ (212.4   $ (128.8
  

 

 

   

 

 

 

Noncontrolling interest

    

Beginning balance

   $ 1,975.6     $ 793.5  

Capital contributions

     612.9       149.7  

Other comprehensive loss allocated to noncontrolling interest

     (0.3     —    

Net income

     78.7       34.0  

Distributions to noncontrolling interest

     (42.5     (28.7
  

 

 

   

 

 

 

Ending balance

   $ 2,624.4     $ 948.5  
  

 

 

   

 

 

 

Total partners’ capital at end of period

   $ 7,998.0     $ 6,728.9  
  

 

 

   

 

 

 

Midcoast Energy Partner, L.P.

On November 13, 2013, MEP, one of our subsidiaries, completed its IPO of 18,500,000 Class A common units representing limited partner interests and subsequently issued an additional 2,775,000 Class A common units pursuant to the underwriter’s over allotment option. MEP received proceeds (net of underwriting discounts, structuring fees and offering expenses) of approximately $354.9 million. MEP used the net proceeds to distribute approximately $304.5 million to us, to pay approximately $3.4 million in revolving credit facility origination and

 

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commitment fees and used approximately $47.0 million to redeem 2,775,000 Class A common units from us. At June 30, 2014, we owned 5.9% of outstanding MEP Class A units, 100% of the outstanding MEP Subordinated Units, 100% of MEP’s general partner and 61% of the limited partner interests in Midcoast Operating.

On June 18, 2014, we agreed to sell a 12.6% limited partner interest in Midcoast Operating to MEP, for $350.0 million in cash, which brought our total ownership interest in Midcoast Operating to 48.4%. This transaction closed on July 1, 2014 and represents our first disposition of additional interests in Midcoast Operating since MEP’s IPO on November 13, 2013. We intend to sell additional interests in our natural gas assets, held through Midcoast Operating, to MEP and use the proceeds from any such sale as a source of funding for us. However, we do not know when, or if, any additional interests will be offered for sale.

Series 1 Preferred Unit Purchase Agreement

On May 7, 2013, we entered into the Series 1 Preferred Unit Purchase Agreement, or Purchase Agreement, with our General Partner pursuant to which we issued and sold 48,000,000 of our Series 1 Preferred Units, representing limited partner interests in us, for aggregate proceeds of approximately $1.2 billion. The closing of the transactions contemplated by the Purchase Agreement occurred on May 8, 2013.

The Preferred Units are entitled to annual cash distributions of 7.50% of the issue price, payable quarterly, which are subject to reset every five years. However, these quarterly cash distributions, during the first full eight quarters ending June 30, 2015, will accrue and accumulate, which we refer to as the Payment Deferral. Thus we will accrue, but not pay these amounts until the earlier of the fifth anniversary of the issuance of the Preferred Units or our redemption of the Preferred Units. The quarterly cash distribution for the three month period ended June 30, 2013 was prorated from May 8, 2013. The preferred unit distributions for the six month period ended June 30, 2014 were $45 million, all of which were deferred. On or after June 1, 2016, at the sole option of the holder of the Preferred Units, the Preferred Units may be converted into Class A Common Units, in whole or in part, at a conversion price of $27.78 per unit plus any accrued, accumulated and unpaid distributions, excluding the Payment Deferral, as adjusted for splits, combinations and unit distributions. At all other times, redemption of the Preferred Units, in whole or in part, is permitted only if: (1) we use the net proceeds from incurring debt and issuing equity, which includes asset sales, in equal amounts to redeem such Preferred Units; (2) a material change in the current tax treatment of the Preferred Units occurs; or (3) the rating agencies’ treatment of the equity credit for the Preferred Units is reduced by 50% or more, all at a redemption price of $25.00 per unit plus any accrued, accumulated and unpaid distributions, including the Payment Deferral.

We issued the Preferred Units at a discount to the market price of the common units into which they are convertible. This discount totaling $47.7 million represents a beneficial conversion feature and is reflected as an increase in common and i-unit unitholders’ and General Partner’s capital and a decrease in Preferred Unitholders’ capital to reflect the fair value of the Preferred Units at issuance on our consolidated statement of partners’ capital for the six month period ended June 30, 2013. The beneficial conversion feature is considered a dividend and is distributed ratably from the issuance date of May 8, 2013, through the first conversion date, which is June 1, 2016, resulting in an increase in preferred capital and a decrease in common and subordinated unitholders’ capital. The impact of accretion of the beneficial conversion feature of $3.7 million and $7.3 million is also included in earnings per unit for the three and six month periods ended June 30, 2014, respectively.

We used the proceeds from the Preferred Unit issuance to repay commercial paper, to finance a portion of our capital expansion program relating to our core liquids and natural gas systems and for general partnership purposes.

8. RELATED PARTY TRANSACTIONS

Investment in Midcoast Energy Partners

We have presented losses from MEP attributable to its public unitholders in the amount of $2.1 million and $1.9 million for the three and six month periods ended June 30, 2014, respectively, in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

 

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Distribution from MEP

The following table presents distributions paid by MEP to us and their public Class A common unitholders during the six month period ended June 30, 2014, representing the noncontrolling interest in MEP.

 

Distribution
Declaration Date

   Distribution Payment Date    Amount Paid to
EEP
     Amount Paid to the
noncontrolling interest
     Total MEP
Distribution
 
          (in millions)  

April 29, 2014

   May 15, 2014    $ 7.8      $ 6.6      $ 14.4  

January 29, 2014

   February 14, 2014      4.1        3.6        7.7  
     

 

 

    

 

 

    

 

 

 
      $ 11.9      $ 10.2      $ 22.1  
     

 

 

    

 

 

    

 

 

 

Joint Funding Arrangement for Alberta Clipper Pipeline

In July 2009, we entered into a joint funding arrangement to finance the construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge Inc., or Enbridge, which we refer to as the Series AC. In March 2010, we refinanced $324.6 million of amounts we had outstanding and payable to our General Partner under the A1 Credit Agreement, a credit agreement between our General Partner and us to finance the Alberta Clipper Pipeline, by issuing a promissory note payable to our General Partner, which we refer to as the A1 Term Note. At such time we also terminated the A1 Credit Agreement. The A1 Term Note matures on March 15, 2020, bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400.0 million. The terms of the A1 Term Note are similar to the terms of our 5.20% senior notes due 2020, except that the A1 Term Note has recourse only to the assets of the United States portion of the Alberta Clipper Pipeline and is subordinate to all of our senior indebtedness. Under the terms of the A1 Term Note, we have the ability to increase the principal amount outstanding to finance the debt portion of the Alberta Clipper Pipeline that our General Partner is obligated to make pursuant to the Alberta Clipper Joint Funding Arrangement for any additional costs associated with our construction of the Alberta Clipper Pipeline that we incur after the date the original A1 Term Note was issued. The increases we make to the principal balance of the A1 Term Note will also mature on March 15, 2020. Pursuant to the terms of the A1 Term Note, we are required to make semi-annual payments of principal and accrued interest. The semi-annual principal payments are based upon a straight-line amortization of the principal balance over a 30 year period as set forth in the approved terms of the cost of service recovery model associated with the Alberta Clipper Pipeline, with the unpaid balance due in 2020. We incurred interest expense under the A1 Term Note of $6.0 million and $12.2 million for the three and six month periods ended June 30, 2014, respectively. We have presented the amounts in “Interest expense, net” on our consolidated statements of income. The approved terms for the Alberta Clipper Pipeline are described in the “Alberta Clipper United States Term Sheet,” which is included as Exhibit I to the June 27, 2008 Offer of Settlement filed with the Federal Energy Regulatory Commission, or FERC, by the OLP and approved on August 28, 2008 (Docket No. OR08-12-000).

A summary of the cash activity for the A1 Term Note for the six month periods ended June 30, 2014 and 2013 are as follows:

 

     A1 Term Note
June 30,
 
     2014     2013  
     (in millions)  

Beginning Balance

   $ 318.0     $ 330.0  

Borrowings

     —         —    

Repayments

     (6.0     (6.0
  

 

 

   

 

 

 

Ending Balance

   $ 312.0     $ 324.0  
  

 

 

   

 

 

 

For the three and six month periods ended June 30, 2014, respectively, we allocated earnings derived from operating the Alberta Clipper Pipeline in the amount of $11.6 million and $21.7 million to our General Partner

 

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for its 66.67% share of the earnings of the Alberta Clipper Pipeline. We also allocated $13.3 million and $26.2 million of such earnings to our General Partner for the three and six month periods ended June 30, 2013, respectively. We have presented the amounts we allocated to our General Partner for its share of the earnings of the Alberta Clipper Pipeline in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Distribution to Series AC Interests

The following table presents distributions paid by the OLP to our General Partner and its affiliate during the six month period ended June 30, 2014, representing the noncontrolling interest in the Series AC, and to us, as the holders of the Series AC 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 AC interests.

 

Distribution
Declaration Date

   Distribution Payment Date    Amount Paid to
Partnership
     Amount paid to the
noncontrolling interest
     Total Series AC
Distribution
 
          (in millions)  

April 30, 2014

   May 15, 2014    $ 6.6      $ 13.1      $ 19.7  

January 30, 2014

   February 14, 2014      6.4        12.8        19.2  
     

 

 

    

 

 

    

 

 

 
      $ 13.0      $ 25.9      $ 38.9  
     

 

 

    

 

 

    

 

 

 

Joint Funding Arrangement for Eastern Access Projects

In May 2012, the OLP amended and restated its limited partnership agreement to establish an additional series of partnership interests, which we refer to as the EA interests. The EA interests were created to finance projects to increase access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as the Eastern Access Projects. From May 2012 through June 27, 2013, our General Partner indirectly owned 60% of all assets, liabilities and operations related to the Eastern Access Projects. On June 28, 2013, we and certain of our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding of the Eastern Access Projects from 40% to 25%. Additionally, within one year of the in-service date, currently scheduled for early 2016, we have the option to increase our economic interest by up to 15 percentage points at cost. We received $90.2 million from our General Partner in consideration for our assignment to it of this portion of our interest, determined based on the capital we had funded prior to June 28, 2013 pursuant to Eastern Access Projects.

Our General Partner has made equity contributions totaling $360.8 million to the OLP during the six month period ended June 30, 2014 to fund its equity portion of the construction costs associated with the Eastern Access Projects.

We allocated earnings from the Eastern Access Projects in the amount of $27.2 million and $48.8 million to our General Partner for its ownership of the EA interest for the three and six month periods ended June 30, 2014, respectively. We allocated earnings derived from the Eastern Access Projects in the amount of $5.1 million and $7.8 million to our General Partner for the three and six month periods ended June 30, 2013, respectively. We have presented the amount allocated to our General Partner in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Distribution to Series EA Interests

The following table presents distributions paid by the OLP to our General Partner and its affiliate during the six month period ended June 30, 2014, representing the noncontrolling interest in the Series EA, and to us, as the

 

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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)         

April 29, 2014

   May 15, 2014    $ 2.5      $ 6.5      $ 9.0  

Joint Funding Arrangement for U.S. Mainline Expansion Projects

In December 2012, the OLP further amended and restated its limited partnership agreement to establish another series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance 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, which we refer to as our Mainline Expansion Projects. From December 2012 through June 27, 2013, the projects were jointly funded by our General Partner at 60% and us at 40%, under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding Agreement. On June 28, 2013, we and certain of our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding in the project from 40% to 25%. Within one year of the last project in-service date, scheduled for early 2016, we have the option to increase our economic interest held at that time by up to 15 percentage points at cost. We received $12.0 million from our General Partner in consideration for our assignment to it of this portion of our interest, determined based on the capital we had funded prior to June 28, 2013, pursuant to the Mainline Expansion Projects.

Our General Partner has made equity contributions totaling $177.7 million and $59.5 million to the OLP for the six month periods ended June 30, 2014 and 2013, respectively, to fund its equity portion of the construction costs associated with the Mainline Expansion Projects.

We allocated earnings from the Mainline Expansion Projects in the amount of $5.7 million and $10.1 million to our General Partner for its ownership of the ME interest for the three and six month periods ended June 30, 2014, respectively. We have presented the amount we allocated to our General Partner in “Net income attributable to noncontrolling interest” 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 580-mile NGL intrastate transportation pipeline and a related NGL gathering system that was placed into service in the fourth quarter of 2013. Our equity investment in the Texas Express NGL system at June 30, 2014 and December 31, 2013, was $381.6 million and $371.3 million, respectively, which is included on our consolidated statements of financial position in “Other assets, net.” For the three and six month periods ending June 30, 2014, we recognized $2.3 million and $1.0 million of equity earnings, respectively, in “Other income (expense)” on our consolidated statements of income related to our investment in the system.

For the three and six month periods ended June 30, 2014, we incurred $6.1 million and $11.4 million, respectively, of pipeline transportation and demand fees from Texas Express NGL system for our Natural Gas business. We did not incur any fees from the Texas Express NGL system for the three and six month periods ended. June 30, 2013. These expenses are recorded in “Cost of natural gas—affiliate” on our consolidated statements of income.

Our Natural Gas business has made commitments to transport up to 120,000 barrels per day, or bpd, of NGLs on the Texas Express NGL system from 2014 to 2023.

 

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Sale of Accounts Receivable

Certain of our subsidiaries entered into a receivables purchase agreement, dated June 28, 2013, which we refer to as the Receivables Agreement, with an indirect wholly-owned subsidiary of Enbridge which was amended on September 20, 2013, and again on December 2, 2013. The Receivables Agreement and the transactions contemplated thereby were approved by the special committee of the board of directors of Enbridge Management. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivable and accrued receivables, or the receivables, of the respective subsidiaries initially up to a monthly maximum of $450.0 million. The Receivables Agreement terminates on December 30, 2016.

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 and six month periods ended June 30, 2014, the cost stemming from the discount on the receivables sold was not material. For the three and six month periods ended June 30, 2014, we sold and derecognized $1,236.0 million and $2,532.7 million of receivables to the Enbridge subsidiary, respectively. For the three and six month periods ended June 30, 2014, the cash proceeds were $1,235.7 million and $2,532.1 million, respectively, which was remitted to the Partnership through our centralized treasury system. As of June 30, 2014, $408.1 million of the receivables were outstanding from customers that had not been collected on behalf of the Enbridge subsidiary.

As of June 30, 2014 and December 31, 2013, we have $33.3 million and $69.4 million, respectively, included in “Restricted cash” on our consolidated statements of financial position, consisting of cash collections related to the Receivables sold that have yet to be remitted to the Enbridge subsidiary as of June 30, 2014.

Affiliate Revenue and Purchases

We record operating revenues in our Liquids segment for storage, transportation and terminaling services we provide to affiliates. Included in our results for the three and six month periods ended June 30, 2014 are operating revenues of $86.0 million and $161.1 million, respectively, and $68.8 million and $139.4 million for the three and six month periods ended June 30, 2013, respectively, related to these transactions.

The purchases of natural gas, NGLs and crude oil from Enbridge and its affiliates are presented in “Cost of natural gas and natural gas liquids—affiliate” on our consolidated statements of income. Included in our results for the three month periods ended June 30, 2014 and 2013 and the six month periods ended June 30, 2014 and 2013 are costs for natural gas, NGLs and crude oil purchases from Enbridge and its affiliates of $38.4 million, $34.5 million, $68.6 million and $72.5 million, respectively.

9. 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 environmental liabilities through 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.

 

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As of June 30, 2014 and December 31, 2013, we had $47.8 million and $25.8 million, respectively, included in “Other long-term liabilities,” 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.

Griffith Terminal Crude Oil Release

On February 25, 2014, a release of approximately 975 barrels of crude oil occurred within the Griffith Terminal in Griffith, Indiana. A repair plan has been reviewed with Pipeline and Hazardous Materials Safety Administration, or PHMSA and repair work has commenced. The released oil was fully contained within our facility and substantially all of the free product was recovered. The released oil did not affect the local community, wildlife or water supply. During the three month period ended June 30, 2014, we increased our total cost estimate by $2.6 million to $7.0 million, primarily due to additional cleanup costs, excluding possible fines and penalties. As of June 30, 2014, we made payments of $2.9 million and we have a remaining estimated liability of $4.1 million.

Lakehead Line 6B Crude Oil Release

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.

On March 14, 2013, we received an order from the Environmental Protection Agency, or EPA, which we refer to as the Order, that defined the scope which requires additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. We submitted our initial proposed work plan required by the EPA on April 4, 2013, and we resubmitted the workplan on April 23, 2013, and again on May 1, 2013, based on EPA comments. The EPA approved the Submerged Oil Recovery and Assessment workplan, or SORA, with modifications on May 8, 2013. We incorporated the modification and submitted an approved SORA on May 13, 2013. At this time we have completed substantially all of the SORA, with the exception of required dredging in and around Morrow Lake and its delta.

We are also working with the Michigan Department of Environmental Quality, MDEQ, to transition submerged oil reassessment, sheen management and sediment trap monitoring and maintenance activities from the EPA to the MDEQ, through a Kalamazoo River Residual Oil Monitoring and Maintenance Work Plan or, the Plan.

As of June 30, 2014, our total cost estimate for the Line 6B crude oil release is $1,157.0 million, which is an increase of $35.0 million as compared to December 31, 2013. On May 28, 2014 the MDEQ, Water Resource Division, approved our Schedule of Work for the remainder of 2014. The total cost increase during the three month period ended June 30, 2014, is primarily related to the finalization of the MDEQ approved Schedule of Work and other costs related to the on-going river restoration activities near Ceresco.

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 June 30, 2014. Our estimates 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 Line 6A & 6B Fines and Penalties section below. Our assumptions include, where applicable, estimates of the expected number of days the associated services will be required and rates that we have obtained from contracts negotiated for the respective service and equipment providers. As we receive invoices for the actual personnel, equipment and services, our estimates will continue to be further refined. Our estimates also consider currently available facts, existing technology and presently enacted laws and regulations.

 

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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 total estimated loss for the cleanup, remediation and restoration associated with the Line 6B crude oil release include the following:

 

     (in millions)  

Response Personnel & Equipment

   $ 539.8  

Environmental Consultants

     212.0  

Professional, regulatory and other

     405.2  
  

 

 

 

Total

   $ 1,157.0  
  

 

 

 

For the six month periods ended June 30, 2014 and 2013, we made payments of $65.0 million and $23.6 million, respectively, for costs associated with the Line 6B crude oil release. As of June 30, 2014 and December 31, 2013, we had a remaining estimated liability of $224.5 million and $258.9 million, respectively.

Lines 6A & 6B Fines and Penalties

On September 9, 2010, a crude oil release occurred on Line 6A in Romeoville, Illinois. At June 30, 2014, our total estimated costs for the Line 6A crude oil release does not include an estimate for fines and penalties, which may be imposed by the EPA and PHMSA, in addition to other federal, state and local governmental agencies.

At June 30, 2014, our estimated costs related to the Line 6B crude oil release included in the total $29.6 million in fines and penalties. Due to the absences of sufficient information, we cannot provide a reasonable estimate of our liability for potential additional fines and penalties that could be assessed in connection with each of the releases. As a result, except for the penalties discussed above, we have not recorded any liability for expected fines and penalties. Discussions with governmental agencies regarding fines and penalties are ongoing.

Insurance Recoveries

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates that renew throughout the year. On May 1 of each year, our insurance program is up for renewal and includes commercial liability insurance coverage that is consistent with coverage considered customary for our industry and includes coverage for environmental incidents such as those we have incurred for the crude oil releases from Lines 6A and 6B, excluding costs for fines and penalties.

A majority of the costs incurred for the crude oil release for Line 6B are covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability. Including our remediation spending through June 30, 2014, we have exceeded the limits of coverage under this insurance policy. As of June 30, 2014, 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 expect to 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 our remaining $145.0 million coverage, as one particular insurer is disputing our recovery eligibility for costs related to our claim on the Line

 

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6B crude oil release and the other remaining insurers assert that their payment is 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.

Of the remaining $103.0 million coverage limit, $85.0 million is the subject matter of the lawsuit Enbridge filed in March 2013 against one particular insurer who is disputing our recovery eligibility for costs related to our claim on the Line 6B oil release. The recovery of the remaining $18.0 million is awaiting resolution of this lawsuit. While we believe those costs are eligible for recovery, there can be no assurance that we will prevail in our lawsuit.

We are pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. Additionally, fines and penalties would not be covered under our existing insurance policy.

Enbridge renewed its comprehensive property and liability insurance programs under which we are insured through April 30, 2015, having a liability aggregate limit of $700.0 million, including sudden and accidental pollution liability. The deductible applicable to oil pollution events will increase to $30.0 million per event, from the current $10.0 million. In the unlikely event that multiple insurable incidents occur which exceed coverage limits 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. Approximately 17 actions or claims are pending against us and our affiliates in state and federal courts in connection with the Line 6B crude oil release, including direct actions and actions seeking class status. Based on the current status of these cases, we do not expect the outcome of these actions to be material. On July 2, 2012, PHMSA announced a Notice of Probable Violation, or NOPV, related to the Line 6B crude oil release, including a civil penalty of $3.7 million that we paid during the third quarter of 2012.

Governmental agencies and regulators have also initiated investigations into the Line 6A crude oil release. One claim was filed against us and our affiliates by the State of Illinois in an Illinois state court in connection with this crude oil release, and the parties are currently operating under an agreed interim order. The costs associated with this order are included in the estimated environmental costs accrued for the Line 6A crude oil release. We are also pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained.

We have accrued a provision for future legal costs and probable losses associated with the Line 6A and Line 6B crude oil releases as described above in this footnote.

10. 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 cost of natural gas we purchase for processing. Our interest rate risk exposure results from changes in interest rates on our variable rate debt and exists at the

 

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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 (i.e., 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 of our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with the risks discussed above through 2018 in accordance with our risk management policies.

Accounting Treatment

Effective January 1, 2014, the Partnership elected to prospectively change its presentation of derivative assets and liabilities from a net basis to a gross basis in the Consolidated Statements of Financial Position. We adopted this change to provide more detailed information about the future economic benefits and obligations associated with our derivative activities in our Consolidated Statements of Financial Position. This change had no impact to the Consolidated Statements of Income, Net income (loss) per limited partner unit, or Partners’ capital.

Non-Qualified Hedges

Many of our derivative financial instruments qualify for hedge accounting treatment as set forth in the authoritative accounting guidance. However, we have transaction types associated with our commodity derivative financial instruments where the hedge structure does not meet the requirements to apply hedge accounting. As a result, these derivative financial instruments do not qualify for hedge accounting and are referred to as non-qualifying. These non-qualifying derivative financial instruments are marked-to-market each period with the change in fair value, representing unrealized gains and losses, included in “Cost of natural gas,” “Operating revenue”, “Power” or “Interest expense” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.

The following transaction types do not qualify for hedge accounting and contribute to the volatility of our income and cash flows:

Commodity Price Exposures:

 

   

Transportation—In our Natural Gas segment, when we transport natural gas from one location to another, the pricing index used for natural gas sales is usually different from the pricing index used for natural gas purchases, which exposes us to market price risk relative to changes in those two indices. By entering into a basis swap, where we exchange one pricing index for another, we can effectively lock in the margin, representing the difference between the sales price and the purchase price, on the combined natural gas purchase and natural gas sale, removing any market price risk on the physical transactions. Although this represents a sound economic hedging strategy, the derivative financial instruments (i.e., the basis swaps) we use to manage the commodity price risk associated with these transportation contracts do not qualify for hedge accounting, since only the future margin has been fixed and not the future cash flow. As a result, the changes in fair value of these derivative financial instruments are recorded in earnings.

 

   

Storage—In our Natural Gas segment, we use derivative financial instruments (i.e., natural gas, crude oil and NGL swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas, crude oil and NGLs and the withdrawal price at which these commodities are sold from storage. The intent of these derivative financial instruments is to lock in the margin, representing the difference between the price paid for the natural gas, crude oil and NGLs injected and the price received upon withdrawal of these commodities from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection

 

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or withdrawal of these commodities, may not occur in the period as originally forecast. This can occur because we have the flexibility to make changes in the underlying injection or withdrawal schedule, based on changes in market conditions. In addition, since the physical commodities are recorded at the lower of cost or market, timing differences can result when the derivative financial instrument is settled in a period that is different from the period the physical commodity is sold from storage. As a result, derivative financial instruments associated with our storage activities can create volatility in our earnings.

 

   

Condensate, Natural Gas and NGL Options—In our Natural Gas segment, we use options to hedge the forecasted commodity exposure of our condensate, NGLs and natural gas. Although options can qualify for hedge accounting treatment, pursuant to the authoritative accounting guidance, we have elected non-qualifying treatment. As such, our option premiums are expensed as incurred. These derivatives are being marked-to-market, with the changes in fair value recorded to earnings each period. As a result, our operating income is subject to volatility due to movements in the prices of condensate, NGLs and natural gas until the underlying long-term transactions are settled.

 

   

Optional Natural Gas Processing Volumes—In our Natural Gas segment, we use derivative financial instruments to hedge the volumes of NGLs produced from our natural gas processing facilities. Some of our natural gas contracts allow us the choice of processing natural gas when it is economical and to cease doing so when processing becomes uneconomic. We have entered into derivative financial instruments to fix the sales price of a portion of the NGLs that we produce at our discretion and to fix the associated purchase price of natural gas required for processing. We typically designate derivative financial instruments associated with NGLs we produce per contractual processing requirements as cash flow hedges when the processing of natural gas is probable of occurrence. However, we are precluded from designating the derivative financial instruments as qualifying hedges of the respective commodity price risk when the discretionary processing volumes are subject to change. As a result, our operating income is subject to increased volatility due to fluctuations in NGL prices until the underlying transactions are settled or offset.

 

   

NGL and Crude Oil Forward Contracts—In our Natural Gas segment, we use forward contracts to fix the price of NGLs and crude oil we purchase and to fix the price of NGLs and crude oil that we sell to meet the demands of our customers that sell and purchase NGLs and crude oil. A sub-group of physical NGL and physical crude oil contracts qualify for the normal purchases and normal sales, or NPNS scope exception. All other forward contracts are being marked-to-market each period with the change in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL and crude oil prices until the forward contracts are settled.

 

   

Natural Gas Forward Contracts—In our Natural Gas segment, we use forward contracts to sell natural gas to our customers. A sub-group of physical natural gas contracts qualify for the normal purchases and normal sales, or NPNS scope exception. All other forward contracts are being marked-to-market each period with the change in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with the changes in fair value of these contracts.

 

   

Crude Oil Contracts—In our Liquids segment, we use forward contracts to hedge a portion of the crude oil length inherent in the operation of our pipelines, which we subsequently sell at market rates. These hedges create a fixed sales price for the crude oil that we will receive in the future. We elected not to designate these derivative financial instruments as cash flow hedges, and as a result, will experience some additional volatility associated with fluctuations in crude oil prices until the underlying transactions are settled or offset.

 

   

Power Purchase Agreements—In our Liquids segment, we use forward physical power agreements to fix the price of a portion of the power consumed by our pumping stations in the transportation of crude oil in our owned pipelines. We designate these derivative agreements as non-qualifying hedges because they fail to meet the criteria for cash flow hedging or the NPNS exception. As various states in which

 

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our pipelines operate have legislated either partially or fully deregulated power markets, we have the opportunity to create economic hedges on power exposure. As a result, our operating income is subject to additional volatility associated with changes in the fair value of these agreements due to fluctuations in forward power prices.

Except for physical power, in all instances related to the commodity exposures described above, the underlying physical purchase, storage and sale of the commodity is accounted for on a historical cost or net realizable value basis rather than on the mark-to-market basis we employ for the derivative financial instruments used to mitigate the commodity price risk associated with our storage and transportation assets. This difference in accounting (i.e., the derivative financial instruments are recorded at fair market value while the physical transactions are recorded at the lower of historical or net realizable value) can and has resulted in volatility in our reported net income, even though the economic margin is essentially unchanged from the date the transactions were consummated. Relating to the power purchase agreements, commodity power purchases are immediately consumed as part of pipeline operations and are subsequently recorded as actual power expenses each period.

Derivative Positions

Our derivative financial instruments are included at their fair values in the consolidated statements of financial position as follows:

 

     June 30,
2014
    December 31,
2013
 
     (in millions)  

Other current assets

   $ 21.7     $ 21.2  

Other assets, net

     35.2       74.4  

Accounts payable and other (1)

     (274.9     (172.0

Other long-term liabilities

     (22.5     (12.3

Due from general partner and affiliates

     0.6       —    

Due to general partner and affiliates

     (0.1     —    
  

 

 

   

 

 

 
   $ (240.0   $ (88.7
  

 

 

   

 

 

 

 

(1)

Includes $3.3 million and $16.7 million of cash collateral at June 30, 2014 and December 31, 2013, respectively.

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.

Accumulated Other Comprehensive Income

We record the change in fair value of our derivative financial instruments that qualify for and are designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, in “Accumulated other comprehensive income”, also referred to as AOCI, a component of “Partners’ capital,” until the underlying hedged transaction occurs. Upon settlement of the designated cash flow hedges, gains (losses) are reclassified to earnings. Also included in AOCI, as of June 30, 2014, are unrecognized losses of approximately $30.0 million associated with derivative financial instruments that qualified for and were classified as cash flow hedges of forecasted transactions that were subsequently de-designated. These losses are reclassified to earnings over the periods during which the originally hedged forecasted transactions affect earnings. During the six month period ended June 30, 2014, unrealized commodity hedge losses of $0.2 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $255.0 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at June 30, 2014, will be reclassified from AOCI to earnings during the next 12 months.

 

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During the first quarter of 2014 it was determined that a portion of forecasted short term debt transactions were not expected to occur, due to changing funding requirements. Since we will require less short-term debt than previously forecasted, we terminated several of our existing interest rate hedges used to lock-in interest rates on our short-term debt issuances as these hedges no longer meet the cash flow hedging requirements. These terminations resulted in realized losses of $0.8 million for the six month period ended June 30, 2014.

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

 

     June 30,
2014
    December 31,
2013
 
     (in millions)  

Counterparty Credit Quality (1)

    

AAA

   $ 0.2     $ 0.3  

AA

     (97.5     (49.7

A (2)

     (145.9     (40.1

Lower than A

     3.2       0.8  
  

 

 

   

 

 

 
   $ (240.0   $ (88.7
  

 

 

   

 

 

 

 

(1)

As determined by nationally-recognized statistical ratings organizations.

(2)

Includes $3.3 million and $16.7 million of cash collateral at June 30, 2014 and December 31, 2013, respectively.

As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, 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 in the balances listed above. We are holding $3.3 million and $16.7 million in cash collateral on our asset exposures at June 30, 2014 and December 31, 2013, respectively. When we are in a position of posting collateral to cover our counterparties’ exposure to our non-performance, the collateral is provided through letters of credit, which are not reflected above.

In the event that our credit ratings were to decline to 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 at the lowest level of investment grade at June 30, 2014, we would have been required to provide additional letters of credit in the amount of $50.3 million.

At June 30, 2014 and December 31, 2013, we had credit concentrations in the following industry sectors, as presented below:

 

     June 30,
2014
    December 31,
2013
 
     (in millions)  

United States financial institutions and investment banking entities

   $ (185.6   $ (85.0

Non-United States financial institutions (1)

     (55.7     0.8  

Other

     1.3       (4.5
  

 

 

   

 

 

 
   $ (240.0   $ (88.7
  

 

 

   

 

 

 

 

(1) 

Includes $3.3 million and $16.7 million of cash collateral at June 30, 2014 and December 31, 2013, respectively.

We are holding $3.3 million and $16.7 million of cash collateral on our asset exposures, and we have provided letters of credit totaling $159.7 million and $76.1 million relating to our liability exposures pursuant to the margin thresholds in effect at June 30, 2014 and December 31, 2013, respectively, under our ISDA® agreements.

 

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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 derivatives is directly with our counterparty and continues until the maturity or termination of the contracts.

Effect of Derivative Instruments on the Consolidated Statements of Financial Position

 

    

Financial Position Location

   Asset Derivatives      Liability Derivatives  
        Fair Value at      Fair Value at  
        June 30,
2014
     December 31,
2013
     June 30,
2014
    December 31,
2013
 
          (in millions)  

Derivatives designated as hedging instruments (1)

             

Interest rate contracts

   Other current assets    $ —        $ 8.1       $ —       $ —     

Interest rate contracts

   Other assets      22.9        57.1         —         —     

Interest rate contracts

   Accounts payable and other  (2)      —          11.9         (240.9     (145.5

Interest rate contracts

   Other long-term liabilities      —          —           (9.8     (11.3

Commodity contracts

   Other current assets      0.9        2.0         —         (0.6

Commodity contracts

   Other assets      0.7        3.5         —         (0.5

Commodity contracts

   Accounts payable and other      —          1.9         (10.0     (12.7

Commodity contracts

   Other long-term liabilities      —          0.6         (1.5     (1.4
     

 

 

    

 

 

    

 

 

   

 

 

 
        24.5        85.1         (262.2     (172.0
     

 

 

    

 

 

    

 

 

   

 

 

 

Derivatives not designated as hedging instruments

             

Commodity contracts

   Other current assets      20.8        11.8         —         (0.1

Commodity contracts

   Other assets      11.6        17.6         —         (3.3

Commodity contracts

   Accounts payable and other      —          5.4         (20.7     (16.3

Commodity contracts

   Other long-term liabilities      —          —           (11.2     (0.2

Commodity contracts

   Due from general partner and affiliates      0.6        —           —         —     

Commodity contracts

   Due to general partner and affiliates      —          —           (0.1     —     
     

 

 

    

 

 

    

 

 

   

 

 

 
        33.0        34.8         (32.0     (19.9
     

 

 

    

 

 

    

 

 

   

 

 

 

Total derivative instruments

      $ 57.5      $ 119.9       $ (294.2   $ (191.9
     

 

 

    

 

 

    

 

 

   

 

 

 

 

(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 $3.3 million and $16.7 million of cash collateral at June 30, 2014 and December 31, 2013, respectively.

 

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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 month period ended June 30, 2014

  

Interest rate contracts

  $ (65.4   Interest expense   $ (3.4   Interest expense   $ (5.3

Commodity contracts

    (3.2   Cost of natural gas     (3.8   Cost of natural gas     (1.1
 

 

 

     

 

 

     

 

 

 

Total

  $ (68.6     $ (7.2     $ (6.4
 

 

 

     

 

 

     

 

 

 

For the three month period ended June 30, 2013

  

Interest rate contracts

  $ 148.7     Interest expense   $ (12.6   Interest expense   $ 1.1   

Commodity contracts

    10.0     Cost of natural gas     2.1     Cost of natural gas     1.8   
 

 

 

     

 

 

     

 

 

 

Total

  $ 158.7       $ (10.5     $ 2.9   
 

 

 

     

 

 

     

 

 

 

For the six month period ended June 30, 2014

  

Interest rate contracts

  $ (137.1   Interest expense   $ (8.1   Interest expense   $ (11.0

Commodity contracts

    (3.3   Cost of natural gas     (10.3   Cost of natural gas     0.6   
 

 

 

     

 

 

     

 

 

 

Total

  $ (140.4     $ (18.4     $ (10.4
 

 

 

     

 

 

     

 

 

 

For the six month period ended June 30, 2013

  

Interest rate contracts

  $ 177.6     Interest expense   $ (20.1   Interest expense   $ 0.6   

Commodity contracts

    8.4     Cost of natural gas     3.6     Cost of natural gas     2.3   
 

 

 

     

 

 

     

 

 

 

Total

  $ 186.0       $ (16.5     $ 2.9   
 

 

 

     

 

 

     

 

 

 

 

(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
 
     (in millions)  

Balance at December 31, 2013

   $ (76.6

Other Comprehensive Income before reclassifications (1)

     (152.4

Amounts reclassified from AOCI (2) (3)

     16.6  

Tax benefit (expense)

     —    
  

 

 

 

Net other comprehensive income

   $ (135.8 ) 
  

 

 

 

Balance at June 30, 2014

   $ (212.4
  

 

 

 

 

(1) 

Excludes NCI loss of $2.1 million reclassified from AOCI at June 30, 2014.

(2) 

Excludes NCI gain of $1.8 million reclassified from AOCI at June 30, 2014.

(3)

For additional details on the amounts reclassified from AOCI, reference the Reclassifications from Accumulated Other Comprehensive Income table below.

 

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Reclassifications from Accumulated Other Comprehensive Income

 

      For the three  month period ended
June 30,
    For the six  month period ended
June 30,
 
       2014          2013         2014          2013    
     (in millions)  

Losses (gains) on cash flow hedges:

          

Interest Rate Contracts (1)

   $ 3.4      $ 12.6     $ 8.1      $ 20.1  

Commodity Contracts (2) (3)

     3.2        (2.1     8.5        (3.6
  

 

 

    

 

 

   

 

 

    

 

 

 

Total Reclassifications from AOCI

   $ 6.6      $ 10.5     $ 16.6      $ 16.5  
  

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) 

Loss (gain) reported within “Interest expense” in the consolidated statements of income.

(2) 

Loss (gain) reported within “Cost of natural gas” in the consolidated statements of income.

(3) 

Excludes NCI gain of $0.6 million and $1.8 million reclassified from AOCI for the three and six month periods ending June 30, 2014.

Effect of Derivative Instruments on Consolidated Statements of Income

 

          For the three month
period ended June 30,
    For the six month period
ended June 30,
 
              2014             2013  (6)             2014             2013  (6)      

Derivatives Not Designated

as Hedging Instruments

  

Location of Gain or (Loss)
Recognized in Earnings (1)

   Amount of Gain or (Loss)
Recognized in Earnings (2)
    Amount of Gain or (Loss)
Recognized in Earnings (2)
 
          (in millions)  

Interest rate contracts

   Interest expense (3)    $ —       $ (0.1   $ —       $ (0.1

Commodity contracts

   Operating revenue (4)      (3.2     4.2        (4.5     2.7   

Commodity contracts

   Operating revenue—Affiliate      0.5       —          0.5       —     

Commodity contracts

   Power      0.2       (0.1     0.5       0.2   

Commodity contracts

   Cost of natural gas  (5)      (13.0     21.6        (19.4     19.2   
     

 

 

   

 

 

   

 

 

   

 

 

 

Total

   $ (15.5   $ 25.6      $ (22.9   $ 22.0   
     

 

 

   

 

 

   

 

 

   

 

 

 

 

(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 qualify for hedge accounting treatment and does not include the ineffective portion of derivatives that are designated as hedging instruments.

(3) 

Includes settlement gains of $0.2 million for the six month period ended June 30, 2013.

(4) 

Includes settlement gains and (losses) of $(0.1) million, $0.9 million, $0.3 million and $1.7 million for the three and six month periods ended June 30, 2014 and June 30, 2013, respectively.

(5) 

Includes settlement gains and (losses) of $(0.3) million, $1.1 million, $(8.8) million and $0.7 million for the three and six month periods ended June 30, 2014 and June 30, 2013, respectively.

(6) 

The effects of derivative instruments on consolidated statements of income for the three and six month periods ended June 30, 2013 have been revised to include settlement gains on derivatives not designated as hedge instruments of $2.0 million and $2.6 million, respectively. The revisions to the disclosure had no impact on previously reported net income or earnings per unit.

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 governs 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.

 

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Offsetting of Financial Assets and Derivative Assets

 

     As of June 30, 2014  
     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

   $ 57.5      $ —        $ 57.5      $ (26.1   $ 31.4  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

Total

   $ 57.5      $ —        $ 57.5      $ (26.1   $ 31.4  
  

 

 

    

 

 

    

 

 

    

 

 

   

 

 

 

 

     As of December 31, 2013  
     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

   $ 119.9      $ (24.3   $ 95.6      $ (18.6   $ 77.0  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Total

   $ 119.9      $ (24.3   $ 95.6      $ (18.6   $ 77.0  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

 

Offsetting of Financial Liabilities and Derivative Liabilities

 

     As of June 30, 2014  
     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 (1)

   $ (297.5   $ —        $ (297.5   $ 26.1      $ (271.4
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ (297.5   $ —        $ (297.5   $ 26.1      $ (271.4
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

     As of December 31, 2013  
     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 (1)

   $ (208.6   $ 24.3      $ (184.3   $ 18.6      $ (165.7
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

Total

   $ (208.6   $ 24.3      $ (184.3   $ 18.6      $ (165.7
  

 

 

   

 

 

    

 

 

   

 

 

    

 

 

 

 

(1) 

Includes $3.3 million and $16.7 million of cash collateral at June 30, 2014 and December 31, 2013 respectively.

 

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Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and December 31, 2013. 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.

 

     June 30, 2014     December 31, 2013  
     Level 1      Level 2     Level 3     Total     Level 1      Level 2     Level 3     Total  
     (in millions)  

Interest rate contracts (1)

   $ —        $ (231.1   $ —       $ (231.1   $ —        $ (96.4   $ —       $ (96.4

Commodity contracts:

                  

Financial

     —          (4.9     (6.4     (11.3     —          6.4       (6.9     (0.5

Physical

     —          —         4.8       4.8       —          —         (0.2     (0.2

Commodity options

     —          —         (2.4     (2.4     —          —         8.4       8.4  
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total

   $ —        $ (236.0   $ (4.0   $ (240.0   $ —        $ (90.0   $ 1.3     $ (88.7
  

 

 

    

 

 

   

 

 

   

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) 

Includes $3.3 million and $16.7 million of cash collateral at June 30, 2014 and December 31, 2013, respectively.

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 over-the-counter, or 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 value our Level 3 derivative instruments, which are fair-valued 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. Increases/(decreases) in the forward commodity price in isolation would result in significantly higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the credit valuation adjustment would change the fair value of the positions.

 

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Table of Contents

Quantitative Information About Level 3 Fair Value Measurements

 

    Fair Value  at
June 30,
2014
    Valuation
Technique
  Unobservable Input   Range (1)     Units

Contract Type

        Lowest     Highest     Weighted
Average
   
    (in millions)                                

Commodity Contracts - Financial

             

Natural Gas

  $ (1.1   Market Approach   Forward Gas Price     3.95       4.91       4.37      MMBtu

NGLs

  $ (5.3   Market Approach   Forward NGL Price     0.29       2.20       1.33      Gal

Commodity Contracts - Physical

             

Natural Gas

  $ 1.2      Market Approach   Forward Gas Price     3.50       5.03       4.31      MMBtu

Crude Oil

  $ (2.5   Market Approach   Forward Crude Oil Price     91.73       109.03       104.63      Bbl

NGLs

  $ 6.3      Market Approach   Forward NGL Price     0.04       2.27       1.19      Gal

Power

  $ (0.2   Market Approach   Forward Power Price     35.27       47.32       39.57      MWh

Commodity Options

             

Natural Gas, Crude and NGLs

  $ (2.4   Option Model   Option Volatility     14     31     24  
 

 

 

             

Total Fair Value

  $ (4.0            
 

 

 

             

 

(1)

Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas; dollars per Gallon, or Gal, for NGLs; dollars per barrel, or Bbl, for Crude Oil; and dollars per Megawatt hour, or MWh, for Power.

Quantitative Information About Level 3 Fair Value Measurements

 

    Fair Value  at
December 31,
2013  (2)
    Valuation
Technique
  Unobservable Input   Range (1)     Units

Contract Type

        Lowest     Highest     Weighted
Average
   
    (in millions)                                

Commodity Contracts - Financial

             

Natural Gas

  $ —        Market Approach   Forward Gas Price     3.64       4.41       4.14      MMBtu

NGLs

  $ (6.9   Market Approach   Forward NGL Price     1.00       2.13       1.38      Gal

Commodity Contracts - Physical

             

Natural Gas

  $ 1.1      Market Approach   Forward Gas Price     3.36       4.82       4.15      MMBtu

Crude Oil

  $ (0.5   Market Approach   Forward Crude Oil Price     86.37       103.04       97.24      Bbl

NGLs

  $ (0.1   Market Approach   Forward NGL Price     0.02       2.19       0.95      Gal

Power

  $ (0.7   Market Approach   Forward Power Price     32.40       38.98       35.07      MWh

Commodity Options

             

Natural Gas, Crude and NGLs

  $ 8.4      Option Model   Option Volatility     18     44     28  
 

 

 

             

Total Fair Value

  $ 1.3               
 

 

 

             

 

(1) 

Prices are in dollars per Millions of British Thermal Units, or MMBtu, for Natural Gas; dollars per Gallon, or Gal, for NGLs; dollars per barrel, or Bbl, for Crude Oil; and dollars per Megawatt hour, or MWh, for Power.

(2) 

Fair values include credit valuation adjustments of approximately $0.1 million of gains.

 

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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, 2014 to June 30, 2014. 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, 2014

   $ (6.9   $ (0.2   $ 8.4     $ 1.3  

Transfer in (out) of Level 3 (1)

     —         —         —         —    

Gains or losses:

        

Included in earnings

     (7.3     4.2       (10.5     (13.6

Included in other comprehensive income

     (3.3     —         —         (3.3

Purchases, issuances, sales and settlements:

        

Purchases

     —         —         0.4       0.4  

Sales

     —         —         (0.5     (0.5

Settlements (2)

     11.1       0.8       (0.2     11.7  
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance as June 30, 2014

   $ (6.4   $ 4.8     $ (2.4   $ (4.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Amount of changes in net assets attributable to the change in derivative gains or losses related to assets still held at the reporting date

   $ (4.6   $ 4.1     $ (10.3   $ (10.8
  

 

 

   

 

 

   

 

 

   

 

 

 

Amounts reported in operating revenue

   $ —       $ 3.6     $ —       $ 3.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(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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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 June 30, 2014 and December 31, 2013.

 

     At June 30, 2014     At December 31, 2013  
                Wtd. Average Price  (2)      Fair Value (3)     Fair Value (3)  
     Commodity   Notional (1)        Receive          Pay        Asset      Liability     Asset      Liability  
                              (in millions)               

Portion of contracts maturing in 2014

                     

Swaps

                     

Receive variable/pay fixed

   Natural Gas     832,732       $ 4.41      $ 4.36       $ 0.1      $ —        $ —        $ —     
   NGL     316,000       $ 62.97      $ 60.27       $ 0.9      $ —        $ 0.6      $ (0.4

Receive fixed/pay variable

   Natural Gas     3,631,800       $ 4.32      $ 4.42       $ 0.3      $ (0.7   $ 0.1      $ (1.0
   NGL     1,612,280       $ 54.87      $ 58.63       $ 1.0      $ (7.1   $ 4.8      $ (12.7
   Crude Oil     725,528       $ 94.78      $ 103.18       $ —        $ (6.1   $ 3.4      $ (5.4

Receive variable/pay variable

   Natural Gas     32,675,300       $ 4.37      $ 4.38       $ 0.7      $ (1.1   $ 0.6      $ (0.1

Physical Contracts

                     

Receive variable/pay fixed

   Natural Gas     79,594       $ 4.36      $ 4.36       $ —        $ —        $ —        $ —     
   NGL     1,355,000       $ 35.27      $ 34.13       $ 1.6      $ (0.1   $ 0.9      $ (0.9
   Crude Oil     81,000       $ 105.17      $ 107.05       $ —        $ (0.1   $ —        $ —     

Receive fixed/pay variable

   Natural Gas     333,893       $ 4.41      $ 4.40       $ —        $ —        $ —        $ —     
   NGL     2,403,278       $ 37.70      $ 38.51       $ 0.5      $ (2.5   $ 0.4      $ (2.6
   Crude Oil     184,000       $ 103.96      $ 104.85       $ 0.2      $ (0.3   $ —        $ (0.4

Pay fixed

   Power (4)     29,510       $ 39.57      $ 46.58       $ —        $ (0.2   $ —        $ (0.7

Receive variable/pay variable

   Natural Gas     107,169,373       $ 4.41      $ 4.40       $ 1.3      $ (0.8   $ 0.9      $ (0.4
   NGL     13,859,812       $ 48.43      $ 48.03       $ 6.4      $ (0.8   $ 5.8      $ (3.7
   Crude Oil     734,242       $ 101.94      $ 104.89       $ 0.8      $ (2.9   $ 1.1      $ (1.2

Portion of contracts maturing in 2015

                     

Swaps

                     

Receive variable/pay fixed

   Natural Gas     19,080       $ 4.47      $ 4.54       $ —        $ —        $ —        $ —     
   NGL     82,500       $ 83.98      $ 84.84       $ —        $ (0.1   $ —        $ —     
   Crude Oil     456,000       $ 96.90      $ 92.94       $ 1.8      $ —        $ —        $ —     

Receive fixed/pay variable

   Natural Gas     596,861       $ 4.74      $ 4.51       $ 0.1      $ —        $ —        $ —     
   NGL     755,000       $ 53.11      $ 54.33       $ 0.9      $ (1.8   $ 1.5      $ (1.1
   Crude Oil     959,665       $ 97.20      $ 97.13       $ 2.4      $ (2.4   $ 8.3      $ —     

Receive variable/pay variable

   Natural Gas     19,885,000       $ 4.29      $ 4.31       $ 0.3      $ (0.7   $ 0.1      $ —     

Physical Contracts

                     

Receive fixed/pay variable

   NGL     295,624       $ 53.31      $ 54.03       $ 0.1      $ (0.3   $ —        $ —     

Receive variable/pay variable

   Natural Gas     79,446,592       $ 4.29      $ 4.29       $ 1.3      $ (0.8   $ 0.5      $ (0.1
   NGL     2,977,353       $ 66.95      $ 66.50       $ 1.9      $ (0.5   $ —        $ —     

Portion of contracts maturing in 2016

                     

Swaps

                     

Receive fixed/pay variable

   Crude Oil     —         $ —        $ —         $ —        $ —        $ 0.7      $ —     

Receive variable/pay fixed

   Crude Oil     68,250       $ 92.49      $ 90.00       $ 0.2      $ —        $ —        $ —     

Receive variable/pay variable

   Natural Gas     5,927,000       $ 4.09      $ 4.11       $ —        $ (0.1   $ —        $ —     

Physical Contracts

                     

Receive variable/pay variable

   Natural Gas     32,721,379       $ 4.16      $ 4.16       $ 0.7      $ (0.6   $ 0.1      $ —     

Portion of contracts maturing in 2017

                     

Physical Contracts

                     

Receive variable/pay variable

   Natural Gas     13,399,743       $ 4.38      $ 4.36       $ 0.2      $ (0.1   $ —        $ —     

 

(1)

Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. Our power purchase agreements are measured in MWh.

(2)

Weighted average prices received and paid are in $/MMBtu for natural gas, $/Bbl for NGL and crude oil and $/MWh for power.

(3)

The fair value is determined based on quoted market prices at June 30, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.1 million of losses and $0.1 million of gains at June 30, 2014 and December 31, 2013, respectively.

(4)

For physical power, the receive price shown represents the index price used for valuation purposes.

 

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The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at June 30, 2014 and December 31, 2013.

 

    At June 30, 2014     At December 31, 2013  
    Commodity   Notional  (1)     Strike
Price  (2)
    Market
Price (2)
    Fair Value (3)     Fair Value (3)  
            Asset     Liability     Asset     Liability  
                          (in millions)  

Portion of option contracts maturing in 2014

             

Puts (purchased)

  Natural Gas     2,208,000      $ 3.90      $ 4.46      $ 0.1     $ —        $ 0.7     $ —     
  NGL     386,400      $ 54.79      $ 56.17      $ 1.3     $ —        $ 2.9     $ —     

Calls (written)

  NGL     230,000      $ 60.92      $ 58.65      $ —       $ (0.6   $ —       $ (1.0

Puts (written)

  Natural Gas     1,472,000      $ 3.90      $ 4.46      $ —       $ (0.1   $ —       $ (0.5

Calls (purchased)

  NGL     46,000      $ 50.40      $ 45.50      $ 0.1     $ —        $ —       $ —     

Portion of option contracts maturing in 2015

             

Puts (purchased)

  Natural Gas     4,015,000      $ 3.90      $ 4.22      $ 1.0     $ —        $ 1.7     $ —     
  NGL     1,259,250      $ 49.40      $ 54.10      $ 4.3     $ —        $ 6.0     $ —     
  Crude Oil     547,500      $ 85.42      $ 96.40      $ 1.2     $ —        $ 1.8     $ —     

Calls (written)

  Natural Gas     1,277,500      $ 5.05      $ 4.22      $ —       $ (0.2   $ —       $ (0.3
  NGL     438,000      $ 57.05      $ 54.83      $ —       $ (2.1   $ —       $ (1.0
  Crude Oil     547,500      $ 91.75      $ 96.40      $ —       $ (4.9   $ —       $ (1.9

Puts (written)

  Natural Gas     1,825,000      $ 4.08      $ 4.22      $ —       $ (0.6   $ —       $ —     

Calls (purchased)

  Natural Gas     1,277,500      $ 5.05      $ 4.22      $ 0.2     $ —        $ —       $ —     

Portion of option contracts maturing in 2016

             

Puts (purchased)

  Natural Gas     1,647,000      $ 3.75      $ 4.24      $ 0.4     $ —        $ —       $ —     
  NGL     366,000      $ 38.22      $ 43.67      $ 1.3     $ —        $ —       $ —     
  Crude Oil     439,200      $ 80.00      $ 91.25      $ 1.5     $ —        $ —       $ —     

Calls (written)

  Natural Gas     1,647,000      $ 4.98      $ 4.24      $ —       $ (0.3   $ —       $ —     
  NGL     366,000      $ 47.02      $ 43.67      $ —       $ (1.8   $ —       $ —     
  Crude Oil     439,200      $ 92.25      $ 91.25      $ —       $ (3.4   $ —       $ —     

 

(1)

Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.

(2)

Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.

(3)

The fair value is determined based on quoted market prices at June 30, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.1 million of gains at June 30, 2014.

 

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Table of Contents

Fair Value Measurements of Interest Rate Derivatives

We enter into interest rate swaps, caps and derivative financial instruments with similar characteristics to manage the cash flow associated with future interest rate movements on our indebtedness. The following table provides information about our current interest rate derivatives for the specified periods.

 

Date of Maturity & Contract Type

  Accounting Treatment   Notional     Average Fixed Rate (1)     Fair Value (2) at  
        June 30,
2014
    December 31,
2013
 
        (dollars in millions)  

Contracts maturing in 2015

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 300       2.43   $ (3.6   $ (6.8 )  

Contracts maturing in 2017

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 400       2.21   $ (14.4   $ (13.8 )  

Contracts maturing in 2018

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 500       2.08   $ 0.2     $ 3.3   

Contracts settling prior to maturity

         

2014—Pre-issuance Hedges (3)

  Cash Flow Hedge   $ 1,850       4.27   $ (242.3   $ (132.7 ) 

2016—Pre-issuance Hedges

  Cash Flow Hedge   $ 500       2.87   $ 25.6     $ 60.8   

 

(1)

Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.

(2)

The fair value is determined from quoted market prices at June 30, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $3.4 million of gains at June 30, 2014 and $7.1 million of losses at December 31, 2013.

(3)

Includes $3.3 million and $16.7 million of cash collateral at June 30, 2014 and December 31, 2013, respectively.

11. INCOME TAXES

We are not a taxable entity for United States federal income tax purposes, or for the majority of states that impose an income tax. Taxes on our net income generally are borne by our unitholders through the allocation of taxable income. Our income tax expense results from the enactment of state income tax laws by the State of Texas that apply to entities organized as partnerships. Our income tax expense is based upon many but not all items included in net income.

We computed our income tax expense by applying a Texas state income tax rate to modified gross margin. The Texas state income tax rate was 0.4% for the six month periods ended June 30, 2014 and 2013. Our income tax expense is $2.0 million and $14.2 million, and $4.0 million and $16.0 million for the three and six month periods ended June 30, 2014 and 2013, respectively.

At June 30, 2014 and December 31, 2013, we have included a current income tax payable of $0.7 million and $0.9 million, respectively, in “Property and other taxes payable” on our consolidated statements of financial position. In addition, at June 30, 2014 and December 31, 2013, we have included a deferred income tax payable of $18.7 million and $17.4 million, respectively, in “Deferred income tax liability,” on our consolidated statements of financial position to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting.

12. SEGMENT INFORMATION

Our business is divided into operating segments, defined as components of the enterprise, about which financial information is available and evaluated regularly by our Chief Operating Decision Maker, collectively comprised of our senior management, in deciding how resources are allocated and performance is assessed.

 

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Each of our reportable segments is a business unit that offers different services and products that is managed separately, because each business segment requires different operating strategies. We have segregated our business activities into two distinct operating segments:

 

   

Liquids; and

 

   

Natural Gas.

During the first quarter of 2014, the Partnership changed its reporting segments. The Marketing segment was combined with the Natural Gas segment to form one new segment called “Natural Gas”. There was no change to the Liquids segment.

This change was a result of the reorganization of EEP resulting from MEP’s IPO, which prompted Management to reassess the presentation of EEP’s reportable segments considering the financial information available and evaluated regularly by EEP’s Chief Operating Decision Maker. The new segment is consistent with how management makes resource allocation decisions, evaluates performance, and furthers the achievement of the Partnership’s long-term objectives. Financial information for the prior periods has been restated to reflect the change in reporting segments.

The following tables present certain financial information relating to our business segments and corporate activities:

 

     For the three month period ended June 30, 2014  
       Liquids          Natural Gas         Corporate  (1)         Total    
     (in millions)  

Operating revenue

   $ 474.3      $ 1,396.8     $ —        $ 1,871.1  

Cost of natural gas

     —          1,259.8       —          1,259.8  

Environmental costs, net of recoveries

     38.2        —         —          38.2  

Operating and administrative

     117.6        103.6       3.4        224.6  

Power

     54.2        —         —          54.2  

Depreciation and amortization

     76.6        36.8       —          113.4  
  

 

 

    

 

 

   

 

 

   

 

 

 
     286.6        1,400.2       3.4        1,690.2  

Operating income (loss)

     187.7        (3.4     (3.4     180.9  

Interest expense, net

     —          —         80.2        80.2  

Allowance for equity used during construction

     —          —         12.6        12.6  

Other income (expense) (2)

     —          2.3       (1.1     1.2  
  

 

 

    

 

 

   

 

 

   

 

 

 

Income (loss) before income tax expense

     187.7        (1.1     (72.1     114.5  

Income tax expense

     —          —         2.0        2.0  
  

 

 

    

 

 

   

 

 

   

 

 

 

Net income (loss)

     187.7        (1.1     (74.1     112.5  

Less: Net income attributable to:

         

Noncontrolling interest

     —          —         42.4        42.4  

Series 1 preferred unit distributions

     —          —         22.5        22.5  

Accretion of discount on Series 1 preferred units

     —          —         3.7        3.7  
  

 

 

    

 

 

   

 

 

   

 

 

 

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

   $ 187.7      $ (1.1   $ (142.7   $ 43.9  
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) 

Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

(2) 

Other income (expense) for our Natural Gas segment includes our equity investment in the Texas Express NGL system which we began recognizing operating costs during the fourth quarter of 2013.

 

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Table of Contents
     For the three month period ended June 30, 2013  
       Liquids          Natural Gas          Corporate  (1)         Total    
     (in millions)  

Operating revenue

   $ 366.3      $ 1,306.4      $ —        $ 1,672.7  

Cost of natural gas

     —          1,115.5        —          1,115.5  

Environmental costs, net of recoveries

     5.2        —          —          5.2  

Operating and administrative

     98.4        116.4        3.2        218.0  

Power

     29.2        —          —          29.2  

Depreciation and amortization

     60.4        35.4        —          95.8  
  

 

 

    

 

 

    

 

 

   

 

 

 
     193.2        1,267.3        3.2        1,463.7  

Operating income (loss)

     173.1        39.1        (3.2     209.0  

Interest expense, net

     —          —          79.5        79.5  

Allowance for equity used during construction

     —          —          8.1        8.1  

Other income

     —          —          0.3        0.3  
  

 

 

    

 

 

    

 

 

   

 

 

 

Income (loss) before income tax expense

     173.1        39.1        (74.3     137.9  

Income tax expense

     —          —          14.2        14.2  
  

 

 

    

 

 

    

 

 

   

 

 

 

Net income (loss)

     173.1        39.1        (88.5     123.7  

Less: Net income attributable to:

          

Noncontrolling interest

     —          —          18.4        18.4  

Series 1 preferred unit distributions

     —          —          13.1        13.1  

Accretion of discount on Series 1 preferred units

     —          —          2.3        2.3  
  

 

 

    

 

 

    

 

 

   

 

 

 

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

   $ 173.1      $ 39.1      $ (122.3   $ 89.9  
  

 

 

    

 

 

    

 

 

   

 

 

 

 

(1) 

Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

 

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Table of Contents
     As of and for the six month period ended June 30, 2014  
     Liquids      Natural Gas     Corporate  (1)     Total  
     (in millions)  

Operating revenue

   $ 907.0      $ 3,043.7  (2)    $ —        $ 3,950.7  

Cost of natural gas

     —          2,748.5        —          2,748.5  

Environmental costs, net of recoveries

     43.2        —          —          43.2  

Operating and administrative

     226.0        212.5        3.1        441.6  

Power

     104.6        —          —          104.6  

Depreciation and amortization

     143.4        73.8        —          217.2  
  

 

 

    

 

 

   

 

 

   

 

 

 
     517.2        3,034.8        3.1        3,555.1  

Operating income (loss)

     389.8        8.9        (3.1     395.6  

Interest expense, net

     —          —          157.1        157.1  

Allowance for equity used during construction

     —          —          33.3        33.3  

Other income (expense)

     —          1.0  (3)      (0.6     0.4  
  

 

 

    

 

 

   

 

 

   

 

 

 

Income (loss) before income tax expense

     389.8        9.9        (127.5     272.2  

Income tax expense

     —          —          4.0        4.0  
  

 

 

    

 

 

   

 

 

   

 

 

 

Net income (loss)

     389.8        9.9        (131.5     268.2  

Less: Net income attributable to:

         

Noncontrolling interest

     —          —          78.7        78.7  

Series 1 preferred unit distributions

     —          —          45.0        45.0  

Accretion of discount on Series 1 preferred units

     —          —          7.3        7.3  
  

 

 

    

 

 

   

 

 

   

 

 

 

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

   $ 389.8      $ 9.9      $ (262.5   $ 137.2  
  

 

 

    

 

 

   

 

 

   

 

 

 

Total assets

   $ 10,335.9      $ 5,301.3  (4)    $ 426.2      $ 16,063.4  
  

 

 

    

 

 

   

 

 

   

 

 

 

Capital expenditures (excluding acquisitions)

   $ 985.0      $ 105.0      $ 1.5      $ 1,091.5  
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) 

Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

(2) 

Total segment revenue and intersegment revenue for the natural gas segment for the six-month period ended June 30, 2014 has been corrected to eliminate intra-segment revenue of $318.7 million that was recorded in error and previously reported on our Quarterly Report on Form 10-Q for the three-month period ended March 31, 2014. This error did not impact previously reported segment operating revenue or consolidated operating revenue for the three-month period ended March 31, 2014.

(3) 

Other income (expense) for our Natural Gas segment includes our equity investment in the Texas Express NGL system which began recognizing operating costs during the fourth quarter of 2013.

(4) 

Total assets for our Natural Gas segment includes our long term equity investment in the Texas Express NGL system.

 

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     As of and for the six month period ended June 30, 2013  
       Liquids          Natural Gas         Corporate  (1)         Total    
     (in millions)  

Operating revenue

   $ 699.2      $ 2,666.5  (2)    $ —        $ 3,365.7  

Cost of natural gas

     —          2,306.9        —          2,306.9  

Environmental costs, net of recoveries

     183.7        —          —          183.7  

Operating and administrative

     185.1        224.2        3.6        412.9  

Power

     62.8        —          —          62.8  

Depreciation and amortization

     117.2        70.8        —          188.0  
  

 

 

    

 

 

   

 

 

   

 

 

 
     548.8        2,601.9        3.6        3,154.3  

Operating income (loss)

     150.4        64.6        (3.6     211.4  

Interest expense, net

     —          —          155.9        155.9  

Allowance for equity used during construction

     —          —          15.9        15.9  

Other income

     —          —          0.6        0.6  
  

 

 

    

 

 

   

 

 

   

 

 

 

Income (loss) before income tax expense

     150.4        64.6        (143.0     72.0  

Income tax expense

     —          —          16.0        16.0  
  

 

 

    

 

 

   

 

 

   

 

 

 

Net income (loss)

     150.4        64.6        (159.0     56.0  

Less: Net income attributable to:

         

Noncontrolling interest

     —          —          34.0        34.0  

Series 1 preferred unit distributions

     —          —          13.1        13.1  

Accretion of discount on Series 1 preferred units

     —          —          2.3        2.3  
  

 

 

    

 

 

   

 

 

   

 

 

 

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

   $ 150.4      $ 64.6      $ (208.4   $ 6.6  
  

 

 

    

 

 

   

 

 

   

 

 

 

Total assets

   $ 7,811.0      $ 5,330.4  (3)    $ 159.6      $ 13,301.0  
  

 

 

    

 

 

   

 

 

   

 

 

 

Capital expenditures (excluding acquisitions)

   $ 733.4      $ 125.1      $ 8.6      $ 867.1  
  

 

 

    

 

 

   

 

 

   

 

 

 

 

(1) 

Corporate consists of interest expense, interest income, allowance for equity used during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

(2) 

Total segment revenue and intersegment revenue for the natural gas segment for the six-month period ended June 30, 2013 has been corrected to eliminate intra-segment revenue of $248.7 million that was recorded in error for the three-month period ended March 31, 2013. This error did not impact previously reported segment operating revenue or consolidate operating revenue for the three-month period ended March 31, 2013.

(3) 

Total assets for our Natural Gas segment includes our long term equity investment in the Texas Express NGL system.

13. REGULATORY MATTERS

Regulatory Accounting

We apply the authoritative regulatory accounting provisions to a number of our pipeline projects that meet the criteria outlined for regulated operations. The rates for the Southern Access, Alberta Clipper and Eastern Access pipelines as well as for our Line 6B 75-mile Replacement Project and Line 14 Project, which are currently the primary applicable projects, are based on a cost-of-service recovery model that follows the FERC’s authoritative guidance and is subject to annual filing requirements with the FERC. Under our cost-of-service tolling methodology, we calculate tolls annually based on forecast volumes and costs. A difference between forecast and actual results causes an under or over collection of revenue in any given year, which is trued-up in the following year. Under the authoritative accounting provisions applicable to our regulated operations, over or under collections of revenue are recognized in the financial statements currently and these amounts are realized the following year. This accounting model matches earnings to the period with which they relate and conforms to how we recover our costs associated with these expansions through the annual cost-of-service filings with the FERC and through toll rate adjustments with our customers. The assets and liabilities that we recognize for regulatory purposes are recorded in “Other current assets” and “Accounts payable and other,” respectively, on our consolidated statements of financial position.

 

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Southern Access Pipeline

For the three and six month period ended June 30, 2014, we over collected revenue for our Southern Access Pipeline primarily due to lower than anticipated power cost adjustments and actual volumes being higher than forecasted volumes used for the April 2013 surcharge filing. This was partially offset by increased income tax allowance resulting from higher than anticipated tax rate. As a result, for the three and six month periods ended June 30, 2014, we adjusted our revenues by a net decrease of $0.4 million and $3.8 million, respectively, on our consolidated statements of income with a corresponding increase in the regulatory liability on our consolidated statements of financial position at June 30, 2014. The amounts will be included in our tolls beginning August 2014 when we update our transportation rates.

For 2013, we under collected revenue for our Southern Access Pipeline primarily due to our actual volumes being lower than the forecasted volumes used for our April 2013 surcharge filing, partially offset by higher than anticipated power credit adjustments. As a result, in 2013, we increased revenues on our consolidated statements of income with a corresponding decrease in the regulatory liability on our consolidated statements of financial position. For the three and six month periods ended June 30, 2014, we decreased our revenues by $4.0 million and $5.7 million, respectively, on our consolidated statement of income with a corresponding amount decreasing the regulatory asset on our consolidated statement of financial position at June 30, 2014. At June 30, 2014 and December 31, 2013, we had a $1.3 million and $7.0 million regulatory asset, respectively, on our consolidated statements of financial position related to this under collection. We will recover these amounts from our customers beginning August 2014.

Alberta Clipper Pipeline

For the three and six month periods ended June 30, 2014, we under collected revenue on our Alberta Clipper Pipeline primarily due to higher than anticipated costs, higher than anticipated equity return used for our April 2013 surcharge filing, and higher than anticipated income tax allowance due to a higher tax rate. The higher costs were partially offset by higher than anticipated volumes. As a result, for the three and six month periods ended June 30, 2014, we increased our revenues by $4.8 million and $7.6 million, respectively, on our consolidated statement of income with a corresponding decrease in the regulatory liability on our consolidated statement of financial position at June 30, 2014 for the differences in transportation volumes. The amounts will be included in our tolls beginning August 2014.

For 2013, we under collected revenue on our Alberta Clipper Pipeline primarily due to our actual volumes being lower than forecasted volumes used for our April 2013 surcharge filing and our income tax rate and return on equity rate base being higher than anticipated, partially offset by higher than anticipated power credit adjustments. As a result, in 2013 we increased our revenues for the amounts we under collected and recorded a decrease in our regulatory liability. For the three and six month periods ended June 30, 2014, we decreased our revenues by $5.2 million and $5.7 million, respectively on our consolidated statement of income with a corresponding amount decreasing the regulatory asset on our consolidated statement of financial position at June 30, 2014. At June 30, 2014 and December 31, 2013 we had regulatory assets of $1.8 million and $7.5 million respectively in our consolidated statements of financial position for the difference in volumes. These amounts will be included in our tolls beginning August 2014 when we update our transportation rates to account for the lower delivered volumes.

Eastern Access Projects

For the three and six month periods ended June 30, 2014, we under collected revenue on an expansion component of our Eastern Access Projects due to an increase in the capital rate base as various components of the project were placed into service, as well as higher than anticipated return on equity rate and it increases income tax allowance due to a higher tax rate. As a result, for the three and six month periods ended June 30, 2014, we increased our revenue by $10.7 million and $11.1 million, respectively on our consolidated statements of income with a corresponding decrease in the regulatory liability on our consolidated statement of financial position at June 30, 2014. The amounts will be collected in our tolls beginning August 2014 when we update our transportation rates.

 

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For 2013, we over collected revenue on our expansion component of our Eastern Access Projects due to a delay in the in-service date. As a result, in 2013 we reduced our revenues on our consolidated statements of income with a corresponding increase in the regulatory liability on our consolidated statements of financial position at December 31, 2013. For the three and six month periods ended June 30, 2014, we increased our revenues by $3.1 million and $5.7 million, respectively, on our consolidated statement of income with a corresponding amount reducing the regulatory liability on our consolidated statement of financial position. At June 30, 2014 and December 31, 2013 we had a regulatory liability of $4.9 million and $10.6 million, respectively. The amounts will be refunded through our tolls when we update our transportation rates which became effective August 2014.

Lakehead Line 6B 75-Mile Replacement Project

For the three and six month periods ended June 30, 2014, we under collected revenue for our Lakehead Line 6B 75-Mile Replacement Project. As a result, for the three and six month periods ended June 30, 2014, we increased our revenue by $3.8 million and $6.3 million, respectively, on our consolidated statements of income with a corresponding decrease in the regulatory liability on our consolidated statements of financial position at June 30, 2014. The amounts will be recovered beginning August 2014 when we update our transportation rates.

For 2013, we under collected revenue for our Lakehead Line 6B 75-Mile Replacement Project due to the capital rate base being higher than anticipated, as well as higher than anticipated return on equity rate and increases income tax allowance due to a higher tax rate. As a result, for year ended December 31, 2013, we increased our revenue on our consolidated statements of income with a corresponding decrease in the regulatory asset on our consolidated statements of financial position. For the three and six month periods ended June 30, 2014, we decreased our revenues by $1.1 million and $1.9 million, respectively, on our consolidated statement of income with a corresponding amount decreasing the regulatory asset on our consolidated statement of financial position. At June 30, 2014 and December 31, 2013 we had a regulatory asset of $1.4 million and $3.3 million, respectively. The amounts will be recovered beginning August 2014 when we update our transportation rates.

Line 14 Pipeline (Part of Lakehead System)

During the three-month period ended June 30, 2014 Line 14 became eligible for the authoritative regulatory accounting provisions due to an expiration of the System Expansion Project II, or SEPII, agreement on March 31, 2014 and negotiations settled with the Canadian Association of Petroleum Producers, or CAPP, to recover the remaining rate base associated with Line 14. Because of the delay of the normal April 1 annual tariff filing we continued to collect on the rate provisions of the 2013 tariff filing in the second quarter of 2014. The 2013 rates contained provisions that were not applicable under the newly negotiated agreement and thus created an overcollection of revenues on this aspect of the tariff during the three-month period ended June 30, 2014. As a result, we decreased our revenues by $22.5 million with a corresponding increase in our regulatory liabilities.

Other Contractual Obligations

Southern Access Pipeline

We have entered into certain contractual obligations with our customers on the Southern Access Pipeline in which a portion of the revenue earned on volumes above certain predetermined shipment levels, or qualifying volumes, are returned to the shippers through future rate adjustments. We record the liabilities associated with this contractual obligation in “Accounts payable and other,” on our consolidated statements of financial position. The amortization for this contractual obligation reflects the related transportation rate adjustment in the subsequent year. At June 30, 2014 and December 31, 2013, we had $1.7 million and $6.1 million, respectively, in qualifying volume liabilities related to the Southern Access Pipeline on our statements of financial position. For the six month periods ended June 30, 2014 and 2013, we increased our revenues by $4.4 million and $7.5 million, respectively, on our consolidated statements of income with a corresponding amount reducing the contractual obligation on our consolidated statements of financial position to account for amortization of the liability.

 

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Alberta Clipper Pipeline

A portion of the rates we charge our customers includes an estimate for annual property taxes. If the estimated property tax we collect from our customers is significantly higher than the actual property tax imposed, we are contractually obligated to refund 50% of the property tax over collection to our customers. At June 30, 2014 and December 31, 2013, we had $6.6 million and $6.9 million, respectively, in property tax over collection liabilities related to our Alberta Clipper Pipeline on our statements of financial position.

For 2013, we also incurred liabilities related to this contractual obligation on the Alberta Clipper Pipeline. As a result, in 2013, we reduced revenues for the amounts due back to our shippers and recorded a liability for the contractual obligation. We amortize the liability on a straight line basis in the following year. For the six month periods ended June 30, 2014 and 2013, we increased our revenues by $3.5 million and $1.5 million, respectively, on our consolidated statements of income with a corresponding amount reducing the contractual obligation on our consolidated statements of financial position.

Allowance for Equity Used During Construction

We are permitted to capitalize and recover costs for rate-making purposes that include an allowance for equity costs during construction, referred to as AEDC. In connection with construction of the Eastern Access Projects, Line 6B 75-mile Replacement and Mainline Expansion Projects, we recorded $33.3 million of AEDC in “Property, plant and equipment” on our consolidated statement of financial position at June 30, 2014, and corresponding $33.3 million of “Allowance for equity used during construction” in our consolidated statement of income for the six month period ended June 30, 2014. We recorded $15.9 million of AEDC in “Property, plant and equipment” on our consolidated statement of financial position at June 30, 2013, and corresponding $15.9 million of “Allowance for equity used during construction” in our consolidated statements of income for the six month period ended June 30, 2013.

FERC Transportation Tariffs

Lakehead System

Effective April 1, 2013, we filed our Lakehead system annual tariff rate adjustment with the FERC to reflect our projected costs and throughput for 2013 and true-ups for the difference between estimated and actual costs and throughput data for the prior year. This tariff rate adjustment filing also included the recovery of costs related to the Flanagan Tank Replacement Project and the Eastern Access Phase 1 Mainline Expansion Project. The Lakehead system utilizes the System Expansion Project II and the Facility Surcharge Mechanism, or FSM, which are components of our Lakehead system’s overall rate structure and allows for the recovery of costs for enhancements or modifications to our Lakehead system.

This tariff filing increased the transportation rate for heavy crude oil movements from the Canadian border to the Chicago, Illinois area by approximately $0.28 per barrel, to approximately $2.13 per barrel. The surcharge is applicable to each barrel of crude oil that is placed on our system beginning on the effective date of the tariff, which we recognize as revenue when the barrels are delivered, typically a period of approximately 30 days from the date shipped.

On June 27, 2014, we filed for an increase to our Lakehead system rates. These rates have an effective date of August 1, 2014. This tariff filing was in part an index filing in accordance with 18 C.F.R.342.3 and in part a compliance filing with certain settlement agreements, which are not subject to FERC indexing. This filing included the increase in rates in compliance with the indexed rate ceilings allowed by the FERC which incorporates the multiplier of 1.038858, which was issued by the FERC on May 14, 2014, in Docket No. RM93-11-000. This filing also reflected our annual tariff rate adjustment for the FSM components or our Lakehead systems’ overall rate structure, as described above. As part of this rate structure our rates reflect our projected costs for 2014 and true-ups for the difference between estimated and actual costs for the prior year. Historically,

 

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we have made the Lakehead system annual tariff rate adjustment for the FSM component of rates with an effective date of April 1 and the index rate filing with an effective date of July 1, however, the filings were delayed as we were in negotiations with CAPP concerning certain components of the tariff rate structure. This negotiation eliminates the SEPII surcharge and added to the FSM component of rates recovery of costs for Line 14, which is virtually the entire asset base associated with the SEPII expansion. The recent negotiation also provides for the recovery of Agreed-Upon Legacy Integrity and Agreed-Upon Future Integrity. These elements are a portion of the costs incurred by the Partnership to maintain the integrity and safety of the pipeline systems. The rates also include recovery of costs related to Eastern Access Phase 2 Mainline Expansion and the 2014 Mainline Expansions.

This tariff filing increased the transportation rate for heavy crude oil movements from the Canadian border to the Chicago, Illinois area by approximately $0.32 per barrel, to approximately $2.49 per barrel. The surcharge is applicable to each barrel of crude oil that is placed on our system beginning on the effective date of the tariff, which we recognize as revenue when the barrels are delivered, typically a period of approximately 30 days from the date shipped.

North Dakota and Ozark Systems

Effective April 1, 2013 for the North Dakota system we filed updates to the calculation of the surcharges on the two previously approve expansion, Phase 5 Looping and Phase 6 Mainline, on our North Dakota system. These expansions are cost-of-service based surcharges that are trued up each year to actual costs and volumes and are not subject to the FERC indexing methodology. This filing increased the average transportation rate for crude oil movements on our North Dakota System by $0.55 per barrel, to an average of approximately $2.06 per barrel.

Effective July 1, 2013, we filed FERC tariffs for our North Dakota and Ozark systems. We increased the rates in compliance with the indexed rate ceilings allowed by FERC which incorporates the multiplier of 1.045923, which was issued by FERC on May 15, 2013, in Docket No. RM93-11-000.

Effective April 1, 2014, we filed updates to the calculation of the surcharges on the two previously approved expansions, Phase 5 Looping and Phase 6 Mainline, on our North Dakota system. As previously mentioned these expansions are cost-of-service based surcharges that are trued up each year to actual costs and volumes and are not subject to the FERC indexing methodology. The filing increased transportation rates for all crude oil movements on our North Dakota system with a destination of Clearbrook, Minnesota by an average of approximately $0.09 per barrel, to an average of approximately $2.21 per barrel.

On May 30, 2014, we filed FERC tariffs with effective dates of July 1, 2014 for our North Dakota and Ozark systems. We increased the rates in compliance with the indexed rate ceilings allowed by the FERC which incorporates the multiplier of 1.038858, which was issued by the FERC on May 14, 2014, in Docket No. RM93-11-000.

14. SUPPLEMENTAL CASH FLOWS INFORMATION

In the “Cash used in investing activities” section of the consolidated statements of cash flows, we exclude changes that did not affect cash. The following is a reconciliation of cash used for additions to property, plant and equipment to total capital expenditures (excluding “Investment in joint venture”):

 

     For the six month
period ended June 30,
 
     2014     2013  
     (in millions)  

Additions to property, plant and equipment

   $ 1,309.0     $ 859.7  

Increase (decrease) in construction payables

     (217.5     7.4  
  

 

 

   

 

 

 

Total capital expenditures (excluding “Investment in joint venture”)

   $ 1,091.5     $ 867.1  
  

 

 

   

 

 

 

 

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15. RECENT ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

In April of 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update No. 2014-08 that both changes the criteria and requires expanded disclosures of reporting discontinued operations. The adoption of the pronouncement is not anticipated to have a material impact on our consolidated financial statements. This accounting update is effective for annual and interim periods beginning after December 15, 2014 and is to be applied prospectively.

In May of 2014, FASB issued Accounting Standards Update No. 2014-09 that outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes the most current revenue recognition guidance, including industry-specific guidance. The impact of the adoption of the pronouncement on our consolidated financial statements is still being evaluated. This accounting update is effective for annual and interim periods beginning on or after December 15, 2016 and may be applied on either a full or modified retrospective basis.

16. SUBSEQUENT EVENTS

364-Day Credit Facility

On July 3, 2014, we amended our 364-Day Credit Facility to extend the revolving credit termination date to July 3, 2015, and to decrease aggregate commitments under the facility by $550.0 million. After these changes, our 364-day Credit Facility now provides to us aggregate lending commitments of $650.0 million.

Equity Restructuring Transaction

Effective July 1, 2014, the General Partner entered into an equity restructuring transaction, or Equity Restructuring, with the Partnership in which the General Partner irrevocably waived its right to receive cash distributions and allocations of items of income, gain, deduction and loss in excess of 2% in respect of its general partner interest in the Previous IDRs, in exchange for the issuance to a wholly-owned subsidiary of the General Partner of (i) 66.1 million units of a new class of Partnership units designated as Class D Units, and (ii) 1,000 units of a new class of Partnership units designated as Incentive Distribution Units. The irrevocable waiver is effective with respect to the calendar quarter ending on June 30, 2014, and each calendar quarter thereafter. See Note 2. Net Income Per Limited Partner Unit.

In connection with the Equity Restructuring, effective July 1, 2014, we amended and restated our partnership agreement. The amendments among other changes and in conjunction with the waiver described above, effectively modified the distribution rights provided for by our partnership agreement to waive the Previous IDRs and to provide distribution rights to the new Class D Units and Incentive Distribution Units. These changes are discussed more fully in our Form 8-A/A filed with the SEC on July 1, 2014. Also, as part of the amendment to our partnership agreement, certain amendments were made to increase the Partnership’s flexibility to maintain and increase interim distributions to unitholders until current and future growth investments by the Partnership begin to generate cash and to enhance the Partnership’s ability to execute its long-term growth plans in a capital efficient and accretive manner.

Midcoast Energy Partners, L.P.

On June 18, 2014, we agreed to sell a 12.6% limited partner interest in Midcoast Operating to MEP, for $350.0 million in cash, which will bring EEP’s total ownership interest in Midcoast Operating to 48.4%. This transaction closed on July 1, 2014, and represents EEP’s first disposition of additional interests in Midcoast Operating since MEP’s initial public offering on November 13, 2013. See Note 7. Partner’s Capital

 

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Distribution to Partners

On July 31, 2014, the board of directors of Enbridge Management declared a distribution payable to our partners on August 14, 2014. The distribution will be paid to unitholders of record as of August 7, 2014 of our available cash of $224.7 million at June 30, 2014, or $0.5550 per limited partner unit. Of this distribution, $187.3 million will be paid in cash, $36.7 million will be distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $0.8 million will be retained from our General Partner from amounts otherwise distributable to it in respect of its general partner interest and limited partner interest to maintain its 2% general partner interest.

Distribution to Series AC Interests

On July 31, 2014, 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 a holder of the Series AC interests, declared a distribution payable to the holders of the Series AC general and limited partner interests. The OLP will pay $14.8 million to the noncontrolling interest in the Series AC, while $7.4 million will be paid to us.

Distribution to Series EA Interests

On July 31, 2014, 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 a holder of the Series EA interests, declared a distribution payable to the holders of the Series EA general and limited partner interests. The OLP will pay $16.7 million to the noncontrolling interest in the Series EA, while $5.6 million will be paid to us.

Distribution from MEP

On July 31, 2014, the board of directors of Midcoast Holdings, L.L.C., acting in its capacity as the general partner of MEP, declared a cash distribution payable to their partners on August 14, 2014. The distribution will be paid to unitholders of record as of August 7, 2014, of MEP’s available cash of $15.0 million at June 30, 2014, or $0.3250 per limited partner unit. MEP will pay $6.9 million to their public Class A common unitholders, while $8.1 million in the aggregate will be paid to us with respect to our Class A common units, subordinated units and to Midcoast Holdings, L.L.C. with respect to its general partner interest.

Midcoast Operating Distribution

On July 31, 2014, the general partner of Midcoast Operating, acting in its capacity as the general partner of Midcoast Operating, declared a cash distribution by Midcoast Operating payable to its partners of record as of August 7, 2014. Midcoast Operating will pay $22.0 million to us and $23.5 million to MEP.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis of our financial condition and results of operations is based on and should be read in conjunction with our consolidated financial statements and the accompanying notes included in Item 1. Financial Statements of this report.

In May 2013, we formed Midcoast Energy Partners, L.P., or MEP. On November 13, 2013, MEP completed its initial public offering, or the IPO, of Class A common units, representing limited partner interests in MEP. On the same date, in connection with the closing of the IPO, certain transactions, among others, occurred pursuant to which we effectively conveyed to MEP all of our limited liability company interests in the general partner of the operating subsidiary of MEP, or Midcoast Operating, and a 39% limited partner interest in Midcoast Operating, in exchange for certain MEP Class A common units and MEP Subordinated Units, approximately $304.5 million in cash as reimbursement for certain capital expenditures with respect to the contributed businesses, and a right to

 

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receive $323.4 million in cash which was paid to us on November 13, 2013. In addition, in connection with the IPO and the closing of the underwriters’ exercise of its over-allotment option, we received $47.0 million from MEP in its redemption of 2,775,000 of MEP Class A common units from us. At June 30, 2014, we owned 5.9% of the outstanding MEP Class A units, 100% of the outstanding MEP Subordinated Units, 100% of MEP’s general partner and 61% of the limited partner interests in Midcoast Operating.

On June 18, 2014, we agreed to sell a 12.6% limited partner interest in Midcoast Operating to our affiliate MEP, for $350.0 million in cash, which brought our total ownership interest in Midcoast Operating to 48.4%. This transaction closed on July 1, 2014, and represents our first disposition of additional interests in Midcoast Operating the IPO. We do not know when, or if, any additional interests will be offered for sale.

RESULTS OF OPERATIONS—OVERVIEW

We provide services to our customers and returns for our unitholders primarily through the following activities:

 

   

Interstate pipeline transportation and storage of crude oil and liquid petroleum;

 

   

Gathering, treating, processing and transportation of natural gas and natural gas liquids, or NGLs, through pipelines and related facilities; and

 

   

Supply, transportation and sales services, including purchasing and selling natural gas and NGLs.

We conduct our business through two business segments: Liquids and Natural Gas. During the first quarter of 2014, the Partnership changed its reporting segments. The Marketing segment was combined with the Natural Gas segment to form one new segment named “Natural Gas”. There was no change to the Liquids segment.

This change was a result of the reorganization of EEP resulting from the IPO which prompted management to reassess the presentation of EEP’s reportable segments considering the financial information available and evaluated regularly by EEP’s Chief Operating Decision Maker. The new segment is consistent with how management makes resource allocation decisions, evaluates performance, and furthers the achievement of the Partnership’s long-term objectives. Financial information for the prior periods has been restated to reflect the change in reporting segments.

 

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The following table reflects our operating income by business segment and corporate charges for each of the three and six month periods ended June 30, 2014 and 2013.

 

     For the three month period
ended June 30,
    For the six month period
ended June 30,
 
         2014             2013             2014             2013      
     (in millions)  

Operating income (loss)

        

Liquids

   $ 187.7     $ 173.1     $ 389.8     $ 150.4  

Natural Gas

     (3.4     39.1       8.9       64.6  

Corporate, operating and administrative

     (3.4     (3.2     (3.1     (3.6
  

 

 

   

 

 

   

 

 

   

 

 

 

Total operating income

     180.9       209.0       395.6       211.4  

Interest expense

     80.2       79.5       157.1       155.9  

Allowance for equity used during construction

     12.6       8.1       33.3       15.9  

Other income

     1.2       0.3       0.4       0.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

     114.5       137.9       272.2       72.0  

Income tax expense

     2.0       14.2       4.0       16.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     112.5       123.7       268.2       56.0  

Less: Net income attributable to:

        

Noncontrolling interest

     42.4       18.4       78.7       34.0  

Series 1 preferred unit distributions

     22.5       13.1       45.0       13.1  

Accretion of discount on Series 1 preferred units

     3.7       2.3       7.3       2.3  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income attributable to general and limited partner ownership interests in Enbridge Energy Partners, L.P.

   $ 43.9     $ 89.9     $ 137.2     $ 6.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

Contractual arrangements in our Liquids and Natural Gas segments expose us to market risks associated with changes in commodity prices where we receive crude oil, natural gas or NGLs in return for the services we provide or where we purchase natural gas or NGLs. Our unhedged commodity position is fully exposed to fluctuations in commodity prices. These fluctuations can be significant if commodity prices experience significant volatility. We employ derivative financial instruments to hedge a portion of our commodity position and to reduce our exposure to fluctuations in crude oil, natural gas and NGL prices. Some of these derivative financial instruments do not qualify for hedge accounting under the provisions of authoritative accounting guidance, which can create volatility in our earnings that can be significant. However, these fluctuations in earnings do not affect our cash flow. Cash flow is only affected when we settle the derivative instrument.

Summary Analysis of Operating Results

Liquids

The following factors primarily affected the $14.6 million and the $239.4 million increases in operating income for the three and six month periods ended June 30, 2014, respectively, when compared to the same period of 2013:

 

   

Increased revenue of $61.7 million and $124.5 million for the three and six month periods ended June 30, 2014, respectively, related to rate increases as a result of tariff filings that became effective July 1, 2013 and April 1, 2014. Operating revenue on our Lakehead system was offset by $19.1 million and $28.6 million for the three and six month periods ended June 30, 2014, respectively, related to regulatory true-ups on Lakehead toll revenues;

 

   

Decreased environmental expense of $140.5 million for the six month period ended June 30, 2014 as compared with the same period in 2013, primarily due lower environmental accruals, net of recoveries, related to the Line 6B crude oil release recognized in the second quarter of 2013;

 

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Increased volumes on our North Dakota and Lakehead systems increased revenue by $52.3 million and $79.9 million for the three and six month periods ended June 30, 2014, respectively, when compared to the same periods in 2013;

 

   

Increased rail revenue of $4.3 million and $12.9 million for the three and six month periods ended June 30, 2014, respectively, on our Berthold Rail system which was placed in service in March of 2013; and

 

   

Increased revenue from our ship or pay agreements of $12.6 million on our North Dakota Bakken system for the six month period ended June 30, 2014.

The increase in operating income was offset by the following factors:

 

   

Increased operating and administrative expenses of $19.2 million and $40.9 million for the three and six month periods ended June 30, 2014, respectively, when compared to the same period in 2013. This is due to increases of $1.5 million and $8.7 million in operational costs for the three and six month periods ended June 30, 2014, respectively, as well as higher workforce related costs, property taxes, and increased administrative, regulatory and compliance support necessary for both the three and six months periods ended June 30, 2014:

 

   

Increased power costs of $25.0 million and $41.8 million for the three and six month periods ended June 30, 2014, respectively, as compared to the same periods in 2013 related to increased volumes; and

 

   

Increased depreciation expense of $16.2 million and $26.2 million for the three and six month periods ended June 30, 2014, respectively, when compared to the same periods in 2013, directly attributable to additional assets placed into service.

Natural Gas

The operating income of our Natural Gas business decreased $42.5 million and $55.7 million for the three and six month periods ended June 30, 2014, respectively, when compared to the same periods in 2013, primarily due to the following:

 

   

Decreased operating income of approximately $17.4 million and $35.3 million for the three and six month periods ended June 30, 2014, respectively, when compared to the same periods in 2013, due to reduced average daily volumes on our major systems primarily attributable to reduced and delayed drilling activity in the Anadarko and East Texas regions;

 

   

Decreased operating income of $33.1 million and $27.0 million for the three and six month periods ended June 30, 2014, respectively, when compared to the same periods in 2013, due to non-cash, mark-to-market net losses from derivative instruments that do not qualify for hedge accounting treatment;

 

   

Decreased operating revenue less the cost of natural gas derived from keep-whole processing earnings for the three and six month periods ended June 30, 2014, of $4.9 million and $12.4 million, respectively, when compared to the same periods in 2013, due to a decline in total NGL production primarily caused by the Avinger plant shutdown from early January until mid-February of 2014;

 

   

Decreased operating income of approximately $3.0 million for the six month period ended June 30, 2014, when compared to the same period in 2013, primarily due to the impact of sustained freezing temperatures which significantly disrupted producer well head production levels and our pipeline operations;

 

   

Decreased operating income of $1.3 million and $2.2 million for the three and six month periods ended June 30, 2014, respectively, due to reduced pricing spreads between our Conway and Mont Belvieu market hubs when compared with the same periods in 2013; and

 

   

Increased depreciation and amortization expense of $1.4 million and $3.0 million for the three and six month periods ended June 30, 2014, respectively, as compared with the same periods in 2013, due to additional assets that were put in service.

 

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The above factors were partially offset for the three and six month periods ended June 30, 2014, as compared with the same periods in 2013 primarily due to:

 

   

Increased operating revenues of $4.4 million for the three and six month periods ended June 30, 2014, related to contractual minimum volume commitment contracts in which our customer has not moved the required volumes; and

 

   

Increased operating income of $1.3 million and $12.7 million due to improvement in natural gas and NGL prices for the three and six month periods ended June 30, 2014, respectively, when compared to the same periods in 2013.

Derivative Transactions and Hedging Activities

We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices and interest rates and to reduce variability in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates. We record all derivative instruments in our consolidated financial statements at fair market value pursuant to the requirements of applicable authoritative accounting guidance. We record changes in the fair value of our derivative financial instruments that do not qualify for hedge accounting in our consolidated statements of income as follows:

 

   

Liquids segment commodity-based derivatives—“Operating revenue” and “Power”

 

   

Natural Gas segment commodity-based derivatives—“Operating revenue” and “Cost of natural gas”

 

   

Corporate interest rate derivatives—“Interest expense”

The changes in fair value of our derivatives are also presented as a reconciling item on our consolidated statements of cash flows. The following table presents the net changes in fair value associated with our derivative financial instruments:

 

     For the three month period
ended June 30,
    For the six month period
ended June 30,
 
         2014             2013             2014             2013      
     (in millions)  

Liquids segment

        

Non-qualified hedges

   $ (5.3   $ 3.2     $ (7.5   $ 1.2  

Natural Gas segment

        

Hedge ineffectiveness

     (1.1     1.8       0.6       2.3  

Non-qualified hedges

     (9.7     20.5       (6.8     18.5  
  

 

 

   

 

 

   

 

 

   

 

 

 

Commodity derivative fair value net gains (losses)

     (16.1     25.5       (13.7     22.0  

Corporate

        

Hedge ineffectiveness

     (5.3     1.1       (11.0     0.6  

Non-qualified interest rate hedges

     —         (0.1     —         (0.3
  

 

 

   

 

 

   

 

 

   

 

 

 

Derivative fair value net gains (losses)

   $ (21.4   $ 26.5     $ (24.7   $ 22.3  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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RESULTS OF OPERATIONS—BY SEGMENT

Liquids

The following tables set forth the operating results and statistics of our Liquids segment assets for the periods presented:

 

     For the three month period
ended June 30,
     For the six month period
ended June 30,
 
         2014              2013              2014              2013      
     (in millions)  

Operating Results:

  

     

Operating revenue

   $ 474.3      $ 366.3      $ 907.0      $ 699.2  
  

 

 

    

 

 

    

 

 

    

 

 

 

Environmental costs, net of recoveries

     38.2        5.2        43.2        183.7  

Operating and administrative

     117.6        98.4        226.0        185.1  

Power

     54.2        29.2        104.6        62.8  

Depreciation and amortization

     76.6        60.4        143.4        117.2  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating expenses

     286.6        193.2        517.2        548.8  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating income

   $ 187.7      $ 173.1      $ 389.8      $ 150.4  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating Statistics

           

Lakehead system:

           

United States (1)

     1,631        1,281        1,596        1,375  

Province of Ontario (1)

     457        402        449        384  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Lakehead system deliveries (1)

     2,088        1,683        2,045        1,759  
  

 

 

    

 

 

    

 

 

    

 

 

 

Barrel miles (billions)

     144        113        279        233  
  

 

 

    

 

 

    

 

 

    

 

 

 

Average haul (miles)

     759        739        753        732  
  

 

 

    

 

 

    

 

 

    

 

 

 

Mid-Continent system deliveries (1)

     176        170        194        196  
  

 

 

    

 

 

    

 

 

    

 

 

 

North Dakota system:

           

Trunkline (1)

     311        148        277        136  

Gathering (1)

     3        3        3        3  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total North Dakota system deliveries (1)

     314        151        280        139  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total Liquids Segment Delivery Volumes (1)

     2,578        2,004        2,519        2,094  
  

 

 

    

 

 

    

 

 

    

 

 

 

 

(1) 

Average barrels per day in thousands.

Three month period ended June 30, 2014 compared with the three month period ended June 30, 2013

The operating revenue of our Liquids segment increased $108.0 million for the three month period ended June 30, 2014 when compared with the same period in 2013, primarily due to (1) increased tariff rates that became effective July 1, 2013 with Federal Energy Regulatory Commission, or FERC, for our Lakehead, North Dakota and Ozark systems, and (2) an increase in volumes on our systems. The increase in tariff rates accounted for $61.7 million of the increase in operating revenue for the three month period ended June 30, 2014 when compared to June 30, 2013.

The increase in tariff rates period-over-period was offset by a $19.1 million decrease in revenues period-over-period as a result of regulatory true-ups related to Lakehead toll revenues. This decrease was due in large part to an over-collection of revenues on the System Expansion Project II, or SEPII, surcharge due to 2013 rates containing provisions that were not applicable under the newly negotiated agreement for Line 14. Generally, these rates would have been updated on April 1 as part of the annual tariff filing. However, due to the renegotiation and the expected delay in the annual filing for the Lakehead system, we over-collected our revenues on SEPII.

 

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The Lakehead tariff that will be effective on August 1, 2014 eliminates the SEPII surcharge as mentioned above and adds to the FSM component of rates recovery of costs for Line 14, Agreed-Upon Legacy Integrity and Agreed-Upon Future Integrity. The FSM revenue requirement for 2014 will be recovered over a 5 month period from August to December versus the usual 9 month period from April to December as done in the typical Lakehead FSM filing schedule. This shortened recovery caused the rates to increase by approximately 4.6% over what they would have been effective April 1.

Operating revenue of our Liquids business increased for the three month period ended June 30, 2014 when compared with the same period in 2013 by $19.7 million due to higher average daily delivery volumes on our Lakehead, Mid-Continent, and North Dakota systems. Average daily volumes delivered increased 574,000 barrels per day during the three month period ended June 30, 2014 compared to the three month period ended June 30, 2013. Our Lakehead system realized higher daily volumes of approximately 405,000 barrels per day, which contributed to increased revenue of $32.6 million.

Additionally, our operating revenue increased for the three month period ended June 30, 2014, when compared to the same period in 2013, due to an increase of $4.3 million from our Berthold Rail and Bakken Systems. The increase is the result of higher average daily delivered volumes when compared to the same period last year.

Environmental costs, net of recoveries, increased $33.0 million for the three month period ended June 30, 2014 when compared with the same period in 2013. On March 14, 2013, we received an order from the EPA, or the Environmental Protection Agency, which we refer to as the Order, which required additional containment and active recovery of submerged oil relating to the Line 6B crude oil release. During the three month period ended June 30, 2014, we had $35 million in cost accruals related to the remediation of the Line 6B crude oil release and no insurance recoveries resulting in $35 million of environmental cost, net of recoveries. During the three month period ended June 30, 2013 we had $40 million of cost accruals related to the Line 6B crude oil release during the period, which were offset by $42 million in insurance recoveries compared to no insurance recoveries for the comparable period this year.

The operating and administrative expenses of our Liquids business increased $19.2 million for the three month period ended June 30, 2014 when compared with the same period in 2013 primarily due to the increased costs of $14.4 million related to workforce expenses. This increase was primarily due to additional costs associated with regulatory and compliance support necessary for our systems. Additionally, operating and administrative expenses increased as a result of increased property taxes of $2.8 million and higher costs related to our integrity program of $6.7 million.

Power costs increased $25.0 million for the three month period ended June 30, 2014 when compared to the same period in 2013 primarily as a result of increased volumes.

The increase in depreciation expense of $16.2 million for the three month period ended June 30, 2014 is directly attributable to the additional assets we have placed in service since the three month period ended June 30, 2013, primarily on our Lakehead System and Eastern Access Project.

Six month period ended June 30, 2014 compared with six month period ended June 30, 2013

Our Liquids segment contributed $389.8 million of operating income during the six month period ended June 30, 2014, representing a $239.4 million increase over the $150.4 million operating income for the same period in 2013. The components comprising the operating income of our Liquids business, such as operating revenue, operating and administrative expenses, power costs, and depreciation expenses changed during the six month period ended June 30, 2014, as compared with the same period in 2013, primarily for the reasons noted above in our three month analysis in addition to the items noted below.

 

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Operating revenue increased by $207.8 million for the six month period ended June 30, 2014, when compared with the same period in 2013, primarily due to increases in tariff rates, delivery volumes and rail revenue as discussed in our analysis above. In addition, operating revenue for the six month period ended June 30, 2014 improved due to increased related ship or pay contracts on our Bakken system of $12.6 million. This is due to a full six months of earnings from the Bakken system which went into service in March of 2013, as well as a stepped up demand charge for certain shippers. These long-term ship-or-pay contracts contain make-up-rights. Make-up-rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiration periods. We recognize revenue associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires, or when it is determined that the likelihood that the shipper will utilize the make-up right is remote.

Environmental costs, net of recoveries decreased $140.5 million for the six month period ended June 30, 2014, when compared with the same period in 2013, which is primarily attributable to the change in costs accruals and insurance recoveries for Line 6B as discussed above. During the six month period ended June 30, 2014 there were $35.0 million in cost accruals compared to $215.0 million accruals for the comparable period ended June 30, 2013. There were no insurance recoveries for the six month period ended June 30, 2014 compared to $42.0 million in insurance recoveries for the comparable period ended June 30, 2013.

Future Prospects Update for Liquids

The table and discussion below summarize the Partnership’s commercially secured projects for the Liquids segment, which have been recently placed into service or will be placed into service in future periods:

 

Projects

   Total Estimated
Capital Costs
     In-Service Date     Funding  
     (in millions)               

Eastern Access Projects:

       

Line 5, Line 62 Expansion, Line 6B Replacement

   $ 2,400        2013—2014  (4)      Joint  (1) 

Eastern Access Upsize—Line 6B Expansion

     310        Early 2016        Joint  (1) 

U.S. Mainline Expansions:

       

Line 61 (ME phase 1)

     160        Q3 2014        Joint  (2) 

Line 67 (ME phase 1)

     220        Q3 2014  (3)      Joint  (2) 

Chicago Area Connectivity (Line 62 twin)

     495        Late 2015        Joint  (2) 

Line 61 (ME phase 2)

     1,160        2015—2016        Joint  (2) 

Line 67 (ME phase 3)

     240        2015        Joint  (2) 

Line 6B 75-mile Replacement Program

     390        Q2 2013—Q1 2014        EEP   

Sandpiper Project

     2,600        Early 2016        Joint  (5) 

Line 3 Replacement Program

     2,600        Second half 2017        EEP  (6) 

 

(1)

Jointly funded 25% by the Partnership and 75% by our General Partner under Eastern Access Joint Funding agreement. Estimated capital costs are presented at 100% before our General Partner’s contributions.

(2)

Jointly funded 25% by the Partnership and 75% by our General Partner under Mainline Expansion Joint Funding agreement. Estimated capital costs are presented at 100% before our General Partner’s contributions.

(3)

Delayed, however, throughput impacts expected to be substantially mitigated by temporary system optimization actions.

(4)

As of June 30, 2014, the following projects related to the Eastern Access Projects have been put into service: (1) Line 5, (2) Line 62 Expansion and (3) a portion of the replacement of Line 6B.

(5)

Since November 25, 2013, the Sandpiper Project is funded 62.5% by the Partnership and 37.5% by Williston Basin Pipeline LLC, an affiliate of Marathon Petroleum Corp., under the North Dakota Pipeline Company Amended and Restated Limited Liability Company Agreement.

(6)

A special committee of independent directors of the Board of EEP has been established to consider a joint funding agreement with Enbridge Inc.

Line 3 Replacement Program

On March 3, 2014, we and Enbridge announced that shipper support was received to replace portions of the existing 1,031-mile Line 3 pipeline on the Canadian Mainline/Lakehead system between Hardisty, Alberta,

 

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Canada and Superior, Wisconsin. Our portion of the Line 3 Replacement Program, referred to as the US L3R Program, includes replacing 358 miles from the U.S./Canadian border at Neche, North Dakota to Superior, Wisconsin. Subject to regulatory and other approvals, the US L3R Program is targeted to be completed in the second half of 2017 at an estimated cost of $2.6 billion. While the L3R Program will not provide an increase in the overall capacity of the mainline system, it supports the safety and operational reliability of the system, enhances flexibility and will allow us to optimize throughput. The L3R Program is expected to achieve an equivalent 34-inch diameter pipeline capacity of approximately 760,000 bpd.

The initial term of the agreement is 15 years. For purposes of the toll surcharge, the agreement specifies a 30 year recovery of the capital based on a cost of service methodology. A special committee of independent directors of the board of EEP has been established to consider a proposal from our General Partner, on behalf of Enbridge, that would establish joint funding arrangements for the US L3R Program by creating an additional jointly owned series of partnership interests in OLP similar to the series established for Alberta Clipper, Eastern Access and Mainline Expansion. We anticipate that joint funding arrangements for the US L3R Program will be completed in 2014.

Line 6B 75-mile Replacement Program

In 2011, we announced plans to replace 75-miles of non-contiguous sections of Line 6B of our Lakehead system. Our Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. The new segments have been completed in components, with approximately 65 miles of segments placed in service in 2013. The two remaining 5-mile segments in Indiana were placed in service in March 2014. The total capital for this replacement program was approximately $390 million. These costs are currently being recovered through our FSM.

Light Oil Market Access Program

On December 6, 2012, we and Enbridge announced our plans to invest in a Light Oil Market Access Program to expand access to markets for growing volumes of light oil production. This program responds to significant recent developments with respect to supply of light oil from U.S. north central formations and western Canada, as well as refinery demand for light oil in the U.S. Midwest and eastern Canada. The Light Oil Market Access Program includes several projects that will provide increased pipeline capacity on our North Dakota regional system, further expand capacity on our U.S. mainline system, upsize the Eastern Access Project, enhance Enbridge’s Canadian mainline terminal capacity and provide additional access to U.S. Midwestern refineries.

Sandpiper Project

Included in the Light Oil Market Access Program is the Sandpiper Project which will expand and extend the North Dakota feeder system by 225,000 Bpd to a total of 580,000 Bpd. The proposed expansion will involve construction of an approximate 600-mile pipeline from Beaver Lodge Station near Tioga, North Dakota to the Superior, Wisconsin mainline system terminal. The new line will twin the existing 210,000 Bpd North Dakota system mainline, which now terminates at Clearbrook Terminal in Minnesota, adding 250,000 Bpd of capacity on the twin line between Tioga and Berthold, North Dakota and 225,000 Bpd of capacity on the twin line between Berthold and Clearbrook both with a new 24-inch diameter pipeline, in addition to adding 375,000 Bpd between Clearbrook and Superior with a 30-inch diameter pipeline. The Sandpiper project is expected to cost approximately $2.6 billion.

Marathon Petroleum Corporation, or MPC, has been secured as an anchor shipper for the Sandpiper project. As part of the arrangement, the Partnership, through its subsidiary, North Dakota Pipeline Company LLC, or NDPC, formerly known as Enbridge Pipelines (North Dakota) LLC, and Williston Basin Pipeline LLC, or Williston, an affiliate of MPC, entered into an agreement to, among other things, admit Williston as a member of NDPC. Williston will fund 37.5% of the Sandpiper Project construction and have the option to participate in

 

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other growth projects within NDPC, unless specifically excluded by the agreement; this investment is not to exceed $1.2 billion in aggregate. In return for funding part of Sandpiper’s construction, Williston will obtain an approximate 27% equity interest in NDPC at the in-service date of Sandpiper, targeted for early 2016.

We filed a petition with the FERC to approve recovering Sandpiper’s costs through a surcharge to the NDPC rates between Beaver Lodge and Clearbrook and a cost of service structure for rates between Clearbrook and Superior. In March 2013, the FERC denied the petition on procedural grounds. We refiled the petition on February 12, 2014 and received approval in the form of a declaratory order from the FERC on May 16, 2014. Furthermore, in late 2013, we held an open season to solicit commitments from shippers for capacity created by the Sandpiper Project. The open season closed in late January 2014 with the receipt of a further capacity commitment which can be accommodated within the planned incremental capacity as identified above. The pipeline is expected to begin service in early 2016, subject to obtaining regulatory and other approvals.

Eastern Access Projects

Since October 2011, we and Enbridge have announced multiple expansion projects that will provide increased access to refineries in the United States Upper Midwest and the Canadian provinces of Ontario and Quebec for light crude oil produced in western Canada and the United States. In 2013, we completed and placed into service the 50,000 Bpd capacity expansion of our Line 5 light crude line between Superior, Wisconsin and the international border at the St. Clair River. Furthermore in 2013, we completed and placed into service the expansion of the Spearhead North pipeline, or Line 62 expansion, between Flanagan, Illinois and the Terminal at Griffith, Indiana. The Line 62 expansion increased capacity from 130,000 Bpd to 235,000 Bpd by adding horsepower.

In 2012, we announced plans to replace additional sections of the our Line 6B in Indiana and Michigan, referred to as the Line 6B Replacement project, including the addition of new pumps and terminal upgrades at Hartsdale, Griffith and Stockbridge, as well as tanks at Flanagan, Stockbridge and Hartsdale, to increase capacity from 240,000 Bpd to 500,000 Bpd. The replacement of the Line 6B sections are in addition to the line 6B 75-Mile Replacement Program discussed above. Portions of the existing 30-inch diameter pipeline are being replaced with 36-inch diameter pipe. The target in-service date for the Line 6B Replacement project was split into two phases, with the segment between Griffith and Stockbridge completed in May 2014 and the segment from Ortonville, Michigan to the international border at the St. Clair River now expected to be completed early in the fourth quarter of 2014. Following detailed engineering estimates completed in the first quarter of 2014 in addition to issues with local ground terrain conditions including tie-ins, the expected capital cost increased by approximately $300 million. These projects, including the previously discussed Line 5 and Line 62 expansion completions, will now cost approximately $2.4 billion and will be undertaken on a cost-of-service basis with shared capital cost risk, such that the toll surcharge will absorb 50% of any cost overruns over $1.85 billion during the Competitive Toll Settlement, or CTS, term, which runs until July 2021.

As part of the Light Oil Market Access Program announced in 2012, the Partnership will expand the Eastern Access Projects, which will include further expansion of the Line 6B component by increasing capacity from 500,000 Bpd to 570,000 Bpd and will include pump station modifications at Griffith, Niles and Mendon, additional modifications at the Griffith and Stockbridge terminals and breakout tankage at Stockbridge. The expected cost of this expansion is now approximately $310 million, which is a decrease of $55 million from the original estimated cost as a result of a more detailed engineering estimate and a proposed tank construction being removed from the scope of the project. This further expansion of the Line 6B component is expected to begin service in early 2016.

These projects collectively referred to as the Eastern Access Projects, will cost approximately $2.7 billion. The Eastern Access Projects are now being funded at 75% by our General Partner and 25% by the Partnership under the Eastern Access Joint Funding agreement, after we exercised the option to reduce our portion of the funding by 15 percentage points on June 28, 2013. Additionally, within one year of the in-service date, scheduled for early 2016, we will have the option to increase our economic interest by up to 15 percentage points at cost.

 

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U.S. Mainline Expansions

In 2012 and 2013, we announced further expansions projects for our mainline pipeline system including (1) expanding our existing 36-inch diameter Alberta Clipper pipeline, or Line 67; (2) expanding of the existing 42-inch diameter Southern Access pipeline, or Line 61; and (3) expanding by constructing a 76-mile, 36-inch diameter twin of the Spearhead North pipeline, or Line 62.

The initial phase of the Alberta Clipper pipeline expansion includes increasing capacity between Neche, North Dakota into the Superior, Wisconsin Terminal from 450,000 Bpd to 570,000 Bpd at an estimated cost of approximately $220 million, while the second phase will add an additional 230,000 Bpd of capacity at an estimated cost of approximately $240 million. These projects require only the addition of pumping horsepower at existing sites with no pipeline construction. Subject to regulatory and other approvals, including an amendment to the current Presidential border crossing permit to allow for operation of the Line 67 pipeline at its currently planned operating capacity of 800,000 Bpd, the expansions will be undertaken on a full cost-of-service basis and are expected to be available for service in the third quarter of 2014 for the initial expansion to 570,000 Bpd and in 2015 for the expansion to 800,000 Bpd. A number of temporary system optimization actions are being undertaken to substantially mitigate any impact on throughput associated with the initial 120,000 Bpd capacity increase. Furthermore, it is anticipated that obtaining regulatory approval for the expansion to 800,000 Bpd will take longer than originally planned although approval is expected mid-2015.

The initial phase of the Southern Access pipeline expansion also includes an increase in capacity between the Superior Terminal and the Flanagan Terminal near Pontiac, Illinois from 400,000 Bpd to 560,000 Bpd at an estimated cost of approximately $160 million. The second phase of the Southern Access pipeline expansion will expand the pipeline to its full 1,200,000 Bpd potential with additional tankage requirements. The Line 61 expansion from 560,000 Bpd to 1,200,000 Bpd is now estimated to cost approximately $1.2 billion, which is a decrease of $90 million from the original estimated cost as a result of a more detailed engineering estimate. Both phases of the expansion require only the addition of pumping horsepower and crude oil tanks at existing sites with no pipeline construction. The first phase of the Line 61 expansion is expected to be available for service in the third quarter of 2014. For the second phase of the Line 61 expansion, which remains subject to regulatory and other approvals, the pump station expansion is expected to be available for service in 2015, while the additional tankage is expected to be completed in 2016.

Furthermore, as part of the Light Oil Market Access Program announced in 2012, the capacity on our Lakehead System between Flanagan, Illinois, and Griffith, Indiana will be expanded by constructing a 79-mile, 36-inch diameter twin of the Spearhead North pipeline, or Line 62, with an initial capacity of 570,000 Bpd, at an estimated cost of $495 million. Subject to regulatory and other approvals, the expansion is expected to begin service in late 2015.

These projects collectively referred to as the U.S. Mainline Expansions projects, will cost approximately $2.3 billion and will be undertaken on a cost-of-service basis. Furthermore, these projects are jointly funded by our General Partner and the Partnership, under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding. On June 28, 2013, we exercised our option to decrease our economic interest and funding of the U.S. Mainline Expansions projects from 40% to 25%. Within one year of the in-service date, scheduled for 2016, the Partnership will have the option to increase its economic interest held at that time by up to 15 percentage points at cost.

Canadian Eastern Access and Mainline Expansion Projects

The Eastern Access Projects and U.S. Mainline Expansions projects complement Enbridge’s strategic initiative of expanding access to new markets in North America for growing production from western Canada and the Bakken Formation.

Since October 2011, Enbridge also announced several complementary Eastern Access and Mainline Expansion Projects. These projects include: (1) partial reversal of Enbridge’s Line 9A in western Ontario to

 

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permit crude oil movements eastbound from Sarnia as far as Westover, Ontario which was completed and placed into service in August 2013; (2) construction of a 35-mile pipeline adjacent to Enbridge’s Toledo Pipeline, originating at the Partnership’s Line 6B in Michigan to serve refineries in Michigan and Ohio which was completed and placed into service in May 2013; (3) reversal of Enbridge’s Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in Quebec; (4) an expansion of Enbridge’s Line 9B to provide additional delivery capacity within Ontario and Quebec; (5) expansions to add horsepower on existing lines on the Enbridge Mainline system from western Canada to the U.S. border; and (6) modifications to existing terminal facilities on the Enbridge Mainline system, comprised of upgrading existing booster pumps, additional booster pumps and new tank line connections in order to accommodate additional light oil volumes and enhance operational flexibility. The outstanding projects have various targeted in-service dates through 2015. The Line 9B projects noted above are subject to fulfillment of certain conditions outlined under the Canadian National Energy Board approval received in March 2014 and are expected to be in service in the fourth quarter of 2014. These projects will enable growing light crude production from the Bakken shale and from Alberta to meet refinery needs in Michigan, Ohio, Ontario and Quebec. These projects will also provide much needed transportation outlets for light crude, mitigating the current discounting of supplies in the basins, while also providing more favorable supply costs to refiners currently dependent on crudes priced off of the Atlantic basin.

Enbridge United States Gulf Coast Projects and Southern Access Extension

A key strength of the Partnership is our relationship with Enbridge. In 2011, Enbridge announced two major United States Gulf Coast market access pipeline projects, which, when completed, will pull more volume through the Partnership’s pipeline and may lead to further expansions of our Lakehead pipeline system. In addition, in 2012 Enbridge announced the Southern Access Extension, which will support the increasing supply of light oil from Canada and the Bakken into Patoka, Illinois.

Flanagan South Pipeline

Enbridge’s Flanagan South Pipeline project will transport more volumes into Cushing, Oklahoma and twin its existing Spearhead pipeline, which starts at the hub in Flanagan, Illinois and delivers volumes into the Cushing hub. The 590-mile, 36-inch diameter pipeline will have a design capacity of approximately 600,000 Bpd and is expected to be mechanically complete by mid-October 2014. However, in the initial years, it is not expected to operate to its full design capacity. In August 2013, the Sierra Club and National Wildlife Federation, the Plaintiff, filed a Complaint for Declaratory and Injunctive Relief, referred to as the Complaint, with the United States District Court for the District of Columbia, or the Court. The Complaint was filed against multiple federal agencies, or the Defendants, and included a request that the Court issue a preliminary injunction suspending previously granted federal permits and ordering Enbridge to discontinue construction of the project on the basis that the Defendants failed to comply with environmental review standards of the National Environmental Protection Act. In September 2013, Enbridge obtained intervener status and joined the Defendants in filing a response in opposition to the motion for preliminary injunction. The Plaintiff’s request for preliminary injunction was denied by the Court in November 2013. A court hearing was held on February 21, 2014 concerning the merits of the Complaint against the federal agencies, but no decision has yet been released.

Seaway Crude Pipeline

In 2011, Enbridge completed the acquisition of a 50% interest in the Seaway Crude Pipeline System, or Seaway. Seaway is a 670-mile pipeline that includes a 500-mile, 30-inch pipeline long-haul system that was reversed in 2012 to enable transportation of oil from Cushing, Oklahoma to Freeport, Texas, as well as a Texas City Terminal and Distribution System that serves refineries in the Houston and Texas City areas. Seaway also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast and provided an initial capacity of 150,000 Bpd. Further pump station additions and modifications completed in January 2013 have increased the capacity to approximately 400,000 Bpd, depending upon the mix of light and heavy grades of crude oil.

In March 2012, based on additional capacity commitments from shippers, plans were announced to proceed with an expansion of the Seaway Pipeline through construction of a second line to more than double its capacity

 

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to 850,000 Bpd. As of July 2014, this 30-inch diameter pipeline was mechanically complete and follows the same route as the existing Seaway Pipeline. Included in the scope of this second line was a 65-mile, 36-inch diameter pipeline lateral from the Seaway Jones Creek facility to Enterprise Product Partners L.P.’s, or Enterprise Product’s, ECHO crude oil terminal, or ECHO Terminal, in Houston, Texas was completed in January 2014. Furthermore, the 100-mile pipeline from Enterprise Product’s ECHO Terminal to the Port Arthur/Beaumont, Texas refining center to provide shippers access to the region’s heavy oil refining capabilities was substantially completed in July 2014. The new 100-mile pipeline offers incremental capacity of 750,000 Bpd.

Southern Access Extension

In December 2012, Enbridge announced that it would undertake the Southern Access Extension project, which will consist of the construction of a 165-mile, 24-inch diameter crude oil pipeline from Flanagan to Patoka, Illinois, as well as additional tankage and two new pump stations. The initial capacity of the new line is expected to be approximately 300,000 Bpd. Effective July 1, 2014, Enbridge entered into an agreement with Lincoln Pipeline LLC, or Lincoln, an affiliate of MPC, to, among other things, admit Lincoln as a partner and participate in the Southern Access Extension. Lincoln has purchased a 35% equity interest in the project and will make additional cash contributions in accordance with the Southern Access Extension’s spend profile in proportion to its 35% interest. Subject to regulatory and other approvals, the project is expected to be placed into service in mid-2015.

Natural Gas

The following tables set forth the operating results of our Natural Gas segment and approximate average daily volumes of natural gas throughput and NGLs produced on our major systems for the periods presented.

 

     For the three month
period ended June 30,
     For the six month
period ended June 30,
 
     2014     2013      2014      2013  
     (in millions)  

Operating revenues

   $ 1,396.8     $ 1,306.4      $ 3,043.7      $ 2,666.5  
  

 

 

   

 

 

    

 

 

    

 

 

 

Cost of natural gas

     1,259.8       1,115.5        2,748.5        2,306.9  

Operating and administrative

     103.6       116.4        212.5        224.2  

Depreciation and amortization

     36.8       35.4        73.8        70.8  
  

 

 

   

 

 

    

 

 

    

 

 

 

Operating expenses

     1,400.2       1,267.3        3,034.8        2,601.9  
  

 

 

   

 

 

    

 

 

    

 

 

 

Operating income (loss)

     (3.4     39.1        8.9        64.6  

Other income

     2.3       —          1.0        —    
  

 

 

   

 

 

    

 

 

    

 

 

 

Net income (loss)

   $ (1.1   $ 39.1      $ 9.9      $ 64.6  
  

 

 

   

 

 

    

 

 

    

 

 

 

Operating Statistics (MMBtu/d)

          

East Texas

     1,029,000       1,211,000        1,000,000        1,231,000  

Anadarko

     826,000       972,000        825,000        968,000  

North Texas

     300,000       344,000        286,000        338,000  
  

 

 

   

 

 

    

 

 

    

 

 

 

Total

     2,155,000       2,527,000        2,111,000        2,537,000  
  

 

 

   

 

 

    

 

 

    

 

 

 

NGL Production (Bpd)

     83,480       91,251        82,004        89,900  
  

 

 

   

 

 

    

 

 

    

 

 

 

Three month period ended June 30, 2014, compared with three month period ended June 30, 2013

The operating income of our Natural Gas business for the three month period ended June 30, 2014, decreased $42.5 million, as compared with the same period in 2013. The most significant area affected was the Natural Gas segment gross margin, representing revenue less cost of natural gas, which decreased $53.9 million for the three month period ended June 30, 2014, as compared with the same period in 2013.

 

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Segment gross margin was impacted by the decrease in unrealized, non-cash, mark-to-market net losses of $33.1 million for the three month period ended June 30, 2014, compared to the same period in 2013, due to losses on our equity gas hedges, hedge ineffectiveness, and overall physical commodity losses from the non-qualifying physical natural gas, NGL, and crude oil contracts.

The following table depicts the effect that non-cash, mark-to-market net gains and losses had on the operating results of our Natural Gas segment for the three and six month periods ended June 30, 2014 and 2013:

 

     For the three month
period ended June 30,
     For the six month
period ended June 30,
 
         2014             2013              2014             2013      
     (in millions)  

Hedge ineffectiveness

   $ (1.1   $ 1.8      $ 0.6     $ 2.3  

Non-qualified hedges

     (9.7     20.5        (6.8     18.5  
  

 

 

   

 

 

    

 

 

   

 

 

 

Derivative fair value gains (losses)

   $ (10.8   $ 22.3      $ (6.2   $ 20.8  
  

 

 

   

 

 

    

 

 

   

 

 

 

We are exposed to fluctuations in commodity prices in the near term on approximately 40% of the physical natural gas, NGLs and condensate we expect to receive as compensation for our services. As a result of this unhedged commodity price exposure, our segment gross margin generally increases when the prices of these commodities are rising and generally decreases when the prices are declining.

Additionally, the segment gross margin for our Natural Gas segment was affected by the reduced production volumes which negatively affected segment gross margin by approximately $17.4 million for the three month period ended June 30, 2014, compared to the same period in 2013. The average daily volumes of our major systems for the three month period ended June 30, 2014, decreased by approximately 372,000 MMBtu/d, or 15%, when compared to the same period in 2013. The average NGL production for the three month period ended June 30, 2014, decreased 7,771 Bpd, or 9%, when compared to the same period in 2013. The decrease in volumes in the Anadarko region was primarily attributable to reduced drilling activity by certain producers, and the loss of a major customer. The decrease in volumes in the East Texas region was primarily attributable to reduced dry gas drilling, and delayed drilling activity and well completions.

The natural gas and NGL production volume outlook on our systems is expected to improve as we progress through 2014. We expect producer drilling plans to accelerate in each of our asset regions later in the year. Additionally, drilling activity by natural gas producers in all regions is expected to target rich gas and oil prospects. This is notable in East Texas where existing processing capacity is full. Completion of the Beckville Cryogenic Processing Plant, which is expected to commence service in early 2015, is expected to alleviate this capacity constraint.

A variable element of the operating results of our Natural Gas segment is derived from processing natural gas on our systems. Under percentage of liquids, or POL, contracts, we are required to pay producers a contractually fixed recovery of NGLs regardless of the NGLs we physically produce or our ability to process the NGLs from the natural gas stream. NGLs that are produced in excess of this contractual obligation in addition to the barrels that we produce under traditional keep-whole gas processing arrangements we refer to collectively as keep-whole earnings. Operating revenue less the cost of natural gas derived from keep-whole earnings for the three month period ended June 30, 2014, decreased $4.9 million from the same period in 2013.

Operating income decreased $1.3 million for the three month period ended June 30, 2014, due to reduced pricing spreads between our Conway and Mont Belvieu market hubs, when compared with the same period in 2013. On our Anadarko system, we purchase certain NGL components at Conway hub prices and then have the option to resell those same NGL components at Mont Belvieu hub prices. For the three months ended June 30, 2014, the prevailing price for NGLs increased approximately 17% per composite barrel at the Conway pricing hub, while increasing approximately 10% per composite barrel at the Mont Belvieu pricing hub, in each case as compared with the prevailing composite barrel prices for the same period in 2013.

 

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The decrease in segment gross margin was offset in part by an increase of $4.4 million for the three months ended June 30, 2014, related to contractual minimum volume commitment contracts in which our customer has not moved the required volumes.

Operating and administrative costs of our Natural Gas segment decreased $12.8 million for the three month period ended June 30, 2014, compared to the same period in 2013, primarily related to lower administrative and pipeline integrity costs.

Depreciation and amortization expense for our Natural Gas segment increased $1.4 million for the three month period ended June 30, 2014, compared with the same period of 2013, due to additional assets that were put in service.

We recognized a $2.3 million equity income in “Other income (expense)” on our consolidated statement of income related to our investment in the Texas Express NGL system, which commenced startup operations during the fourth quarter of 2013. The Texas Express NGL system operates using ship or pay contracts. These ship or pay contracts contain make-up rights provisions, which are earned when minimum volume commitments are not utilized during the contract period but are also subject to contractual expiry periods. Revenue associated with these make-up rights is deferred when more than a remote chance of future utilization exists. For the three month period ended June 30, 2014, the deferred revenue on the ship or pay contracts amounted to $1.1 million.

Six month period ended June 30, 2014, compared with six month period ended June 30, 2013

The operating income of our Natural Gas business for the six month period ended June 30, 2014, decreased $55.7 million, as compared with the same period in 2013. The most significant area affected was the Natural Gas segment gross margin, representing revenue less cost of natural gas, which decreased $64.4 million for the six month period ended June 30, 2014, as compared with the same period in 2013.

The segment gross margin for our Natural Gas segment was affected by the reduced production volumes which negatively affected segment gross margin by approximately $35.3 million for the six month period ended June 30, 2014, compared to the same period in 2013. The average daily volumes of our major systems for the six month period ended June 30, 2014, decreased by approximately 426,000 MMBtu/d, or 17%, when compared to the same period in 2013. The average NGL production for the six month period ended June 30, 2014, decreased by 7,896 Bpd, or 9%, when compared to the same period in 2013. These decreases in volumes on our major systems were primarily attributable to reduced drilling activity by certain producers in the Anadarko region, reduced dry gas drilling, and delayed drilling activity and well completions in East Texas.

Segment gross margin was impacted by the decrease in non-cash, mark-to-market net losses of $27.0 million for the six month period ended June 30, 2014, compared to the same period in 2013 due to losses on our equity gas hedges, hedge ineffectiveness, and overall physical commodity losses from the non-qualifying physical natural gas, NGL, and crude oil contracts.

Operating revenue less the cost of natural gas derived from keep-whole earnings for the six month period ended June 30, 2014, decreased $12.4 million from the same period in 2013.

Operating income decreased approximately $3.0 million for six month period ended June 30, 2014, primarily due to the impact of sustained freezing temperatures in the first quarter 2014, which significantly disrupted producer well head production levels and our pipeline operations.

Operating income decreased $2.2 million for the six month period ended June 30, 2014, due to reduced pricing spreads between our Conway and Mont Belvieu market hubs when compared with the same period in 2013. On our Anadarko system, we purchase certain NGL components at Conway hub prices and then have the

 

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option to resell those same NGL components at Mont Belvieu hub prices. For the six months ended June 30, 2014, the prevailing price for NGLs increased approximately 20% per composite barrel at the Conway pricing hub, while increasing approximately 13% per composite barrel at the Mont Belvieu pricing hub, in each case as compared with the prevailing composite barrel prices for the same period in 2013.

The decrease in segment gross margin was partially offset by an increase of $4.4 million for the six months ended June 30, 2014, related to contractual minimum volume commitment contracts in which our customer has not moved the required volumes.

Operating and administrative costs of our Natural Gas segment decreased $11.7 million for the six month period ended June 30, 2014, compared to the same period in 2013, primarily related to lower administrative and pipeline integrity costs.

Depreciation and amortization expense for our Natural Gas segment increased $3.0 million, for the six month period ended June 30, 2014, compared with the same period of 2013, due to additional assets that were put in service.

We recognized $1.0 million in equity earnings in “Other income (expense)” on our consolidated statements of income related to our investment in the Texas Express NGL system, which commenced startup operations during the fourth quarter of 2013. The Texas Express NGL system operates using ship or pay contracts. These ship or pay contracts contain make-up rights provisions, which are earned when minimum volume commitments are not utilized during the contract period but are also subject to contractual expiry periods. Revenue associated with these make-up rights is deferred when more than a remote chance of future utilization exists. For the six month period ended June 30, 2014, the deferred revenue on the ship or pay contracts amounted to $3.2 million.

Future Prospects for Natural Gas

We intend to expand our natural gas gathering and processing services through internal growth projects designed to provide exposure to incremental supplies of natural gas at the wellhead, increase opportunities to serve additional customers, including new wholesale customers, and allow expansion of our treating and processing businesses. Additionally, we will pursue acquisitions to expand our natural gas services in situations where we have natural advantages to create additional value. The paragraph below summarizes the Partnership’s commercially secured project for the Natural Gas segment, which we expect to place into service in future periods.

Beckville Cryogenic Processing Plant

In April 2013, we announced plans to construct a cryogenic natural gas processing plant near Beckville in Panola County, Texas, which we refer to as the Beckville processing plant. This plant is expected to serve existing and prospective customers pursuing production in the Cotton Valley formation. We expect our Beckville processing plant to be capable of processing approximately 150 MMcf/d of natural gas and producing approximately 8,500 Bpd of NGLs to accommodate the additional liquids-rich natural gas being developed within this geographical area in which our East Texas system operates. We estimate the cost of constructing the plant to be approximately $145 million and expect it to commence service in early 2015.

The project is funded by the Partnership and MEP based on their proportionate ownership percentages in Midcoast Operating, which was 61% and 39%, respectively, at June 30, 2014. On July 1, 2014, MEP acquired an additional 12.6% interest in Midcoast Operating from us for $350 million. The Partnership’s and MEP’s ownership in Midcoast Operating is 48.4% and 51.6%, respectively, after the transaction date. For additional information on this transaction, see Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Subsequent Events.

 

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Corporate

Our corporate activities consist of interest expense, interest income, allowance for equity during construction, noncontrolling interest and other costs such as income taxes, which are not allocated to the business segments.

 

      For the three month
period ended June 30,
    For the six month
period ended June 30,
 
       2014         2013         2014         2013    
     (in millions)  

Operating Results:

        

Operating and administrative expenses

   $ 3.4     $ 3.2     $ 3.1     $ 3.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating loss

     (3.4     (3.2     (3.1     (3.6

Interest expense, net

     80.2       79.5       157.1       155.9  

Allowance for equity used during construction

     12.6       8.1       33.3       15.9  

Other income (expense)

     (1.1     0.3       (0.6     0.6  

Income tax expense

     2.0       14.2       4.0       16.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss

     (74.1     (88.5     (131.5     (159.0

Noncontrolling interest

     42.4       18.4       78.7       34.0  

Series 1 preferred unit distributions

     22.5       13.1       45.0       13.1  

Accretion of discount on Series 1 preferred units

     3.7       2.3       7.3       2.3  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net loss attributable to general and limited partners

   $ (142.7   $ (122.3   $ (262.5   $ (208.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Our interest cost for the three and six month periods ended June 30, 2014 and 2013 is comprised of the following:

 

     For the three month
period ended June 30,
    For the six month
period ended June 30,
 
       2014         2013         2014         2013    
     (in millions)  

Interest expense

   $ 80.2     $ 79.5     $ 157.1     $ 155.9  

Interest capitalized

     10.2       12.1       24.1       26.4  
  

 

 

   

 

 

   

 

 

   

 

 

 

Interest cost incurred

   $ 90.4     $ 91.6     $ 181.2     $ 182.3  
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average interest rate

     6.2     6.1     6.4     6.1

Three month period ended June 30, 2014, compared with three month period ended June 30, 2013

The $14.4 million decrease in our net loss for the three month period ended June 30, 2014, as compared to the same period in 2013 was primarily attributable to the allowance for equity used during construction, or AEDC, and income tax expense.

Income tax expense decreased $12.2 million for the three month period ended June 30, 2014, compared to the same period in June 30, 2013, primarily due to $6.6 million of income tax expense recognized for the three month period ended June 30, 2013, related to the Texas Legislature passing House Bill 500, or HB 500, which was subsequently signed into law in June 2013. The most significant change in the law for us is that HB 500 allows a pipeline company that transports oil, gas, or other petroleum products owned by others to subtract as Cost of Goods Sold, its depreciation, operations, and maintenance costs related to the services provided. Under the new law, we are allowed additional deductions against income for Texas margin tax purposes. The decrease in income taxes period-to-period is a result of the change in this law. See Note 11. Income Taxes for further discussion regarding this new tax law.

 

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AEDC increased $4.5 million for the three month period ended June 30, 2014, compared with the corresponding period in 2013, primarily related to our Eastern Access projects, which also contributed to the decrease in net loss.

Six month period ended June 30, 2014, compared with six month period ended June 30, 2013

The results for corporate activities for the six month period ended June 30, 2014, compared to the same period in 2013, changed for the same reasons as noted in the three month analysis above.

Other Matters

Alberta Clipper Pipeline Joint Funding Arrangement

In July 2009, we entered into a joint funding arrangement to finance construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge, including our General Partner. In connection with the joint funding arrangement, we allocated earnings derived from operating the Alberta Clipper Pipeline in the amount of $11.6 million and $13.3 million to our General Partner for its 66.67% share of the earnings of the Alberta Clipper Pipeline for the three month periods ended June 30, 2014 and 2013, respectively. We allocated earnings derived from operating the Alberta Clipper Pipeline in the amount of $21.7 million and $26.2 million to our General Partner for the six month periods ended June 30, 2014, and June 30, 2013, respectively. We have presented the amounts we allocated to our General Partner for its share of the earnings of the Alberta Clipper Pipeline in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Joint Funding Arrangement for Eastern Access Projects

In May 2012, the OLP amended and restated its partnership agreement to establish an additional series of partnership interests, which we refer to as the EA interests. The EA interests were created to finance projects to increase access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as the Eastern Access Projects. From May 2012 through June 27, 2013, our General Partner indirectly owned 60% of all assets, liabilities and operations related to the Eastern Access Projects. On June 28, 2013, we and our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding of the Eastern Access Projects from 40% to 25%. Additionally, within one year of the in-service date, scheduled for early 2016, we have the option to increase our economic interest by up to 15 percentage points at cost. We received $90.2 million from our General Partner in consideration for our assignment to it of this portion of our interest, determined based on the capital we had funded prior to June 28, 2013, pursuant to Eastern Access Projects.

We allocated earnings from the Eastern Access Projects in the amount of $27.2 million and $5.1 million to our General Partner for its ownership of the EA interest for the three month periods ended June 30, 2014, and June 30, 2013, respectively. We allocated earnings derived from the Eastern Access Projects in the amount of $48.8 million and $7.8 million to our General Partner for the six month periods ended June 30, 2014, and June 30, 2013, respectively. We have presented this amount we allocated to our General Partner in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Joint Funding Arrangement for the U.S. Mainline Expansion

In December 2012, the OLP further amended and restated its limited partnership agreement to establish another series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance 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, which we refer to as our Mainline Expansion Projects. From December 2012 through June 27, 2013, the projects were jointly funded by our General Partner at 60% and the Partnership at 40%, under the Mainline Expansion Joint Funding Agreement,

 

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which parallels the Eastern Access Joint Funding Agreement. On June 28, 2013, we and our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding in the projects from 40% to 25%. We received $12.0 million from our General Partner in consideration for our economic interest. Additionally, within one year of the in-service date, currently scheduled for 2016, we have the option to increase our economic interest held at that time by up to 15 percentage points at costs.

We allocated earnings from the Mainline Expansion Projects in the amount of $5.7 million and $10.1 million to our General Partner for its ownership of the ME interest for the three and six month periods ended June 30, 2014. We have presented the amount we allocated to our General Partner in “Net income attributable to noncontrolling interest” in our consolidated statements of income.

LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

Our primary source of short-term liquidity is provided by our $1.5 billion commercial paper program, which is supported by our $1.975 billion senior unsecured revolving credit facility, which we refer to as the Credit Facility, and our $1.2 billion credit agreement, which we refer to as the 364-Day Credit Facility. We refer to the 364-Day Credit Facility and the Credit Facility as our Credit Facilities. We access our $1.5 billion commercial paper program primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the interest rates available to us for commercial paper are more favorable than the rates available under our Credit Facilities.

As set forth in the following table, we had approximately $2.1 billion of liquidity available to us at June 30, 2014, to meet our ongoing operational, investment and financing needs, as well as the funding requirements associated with the environmental remediation costs resulting from the crude oil releases on Lines 6A and 6B. In addition, MEP had $0.6 billion of available liquidity from cash on hand and under the MEP Credit Agreement as set forth in the following table.

 

    EEP     MEP  
    (in millions)  

Cash and cash equivalents

  $ 113.9     $ 236.0  

Total credit available under EEP’s Credit Facilities

    3,175.0       —    

Total credit available under MEP’s Credit Agreement

    —         850.0  

Less: Amounts outstanding under MEP’s Credit Agreement

    —         475.0  

Principal amount of commercial paper issuances

    1,065.0       —    

Letters of credit outstanding

    160.3       —    
 

 

 

   

 

 

 

Total

  $ 2,063.6     $ 611.0  
 

 

 

   

 

 

 

General

Our primary operating cash requirements consist of normal operating expenses, maintenance capital expenditures, distributions to our partners and payments associated with our risk management activities. We expect to fund our current and future short-term cash requirements for these items from our operating cash flows supplemented as necessary by issuances of commercial paper and borrowings on our Credit Facilities. Margin requirements associated with our derivative transactions are generally supported by letters of credit issued under our Credit Facilities.

Our current business strategy emphasizes developing and expanding our existing Liquids and Natural Gas businesses through organic growth and targeted acquisitions. We expect to initially fund our long-term cash requirements for expansion projects and acquisitions, as well as retire our maturing and callable debt, first from

 

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operating cash flows and then from issuances of commercial paper and borrowings on our Credit Facilities. We expect to obtain permanent financing as needed through the issuance of additional equity and debt securities, which we will use to repay amounts initially drawn to fund these activities, although there can be no assurance that such financings will be available on favorable terms, if at all. In addition, we intend to sell additional interests in Midcoast Operating entity to MEP to raise capital over the course of the next several years. Although this is our intent, there is no assurance that any transactions will occur as they are subject to, among other things, obtaining agreement from MEP and its board of directors around the commercial terms of such a sale. When we have attractive growth opportunities in excess of our own capital raising capabilities, the General Partner has provided supplementary funding, or participated directly in projects, to enable us to undertake such opportunities. If in the future we have attractive growth opportunities that exceed capital raising capabilities, we could seek similar arrangements from the General Partner, but there can be no assurance that this funding can be obtained.

As of June 30, 2014, we had a working capital deficit of approximately $1.0 billion and approximately $2.1 billion of liquidity to meet our ongoing operational, investing and financing needs as of June 30, 2014, as shown above, as well as the funding requirements associated with the environmental remediation costs resulting from the crude oil releases on Lines 6A and 6B. In addition, MEP had $0.6 billion of available liquidity from cash on hand and under its Credit Agreement.

Capital Resources

Equity and Debt Securities

Execution of our growth strategy and completion of our planned construction projects contemplate our accessing the public and private equity and credit markets to obtain the capital necessary to fund these activities. We have issued a balanced combination of debt and equity securities to fund our expansion projects and acquisitions. Our internal growth projects and targeted acquisitions will require additional permanent capital and require us to bear the cost of constructing and acquiring assets before we begin to realize a return on them. If market conditions change and capital markets again become constrained, our ability and willingness to complete future debt and equity offerings may be limited. The timing of any future debt and equity offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.

Series 1 Preferred Unit Purchase Agreement

On May 7, 2013, we entered into the Series 1 Preferred Unit Purchase Agreement, or Purchase Agreement, with our General Partner pursuant to which we issued and sold 48,000,000 of our Series 1 Preferred Units, representing limited partner interests in us, for aggregate proceeds of approximately $1.2 billion. The closing of the transactions contemplated by the Purchase Agreement occurred on May 8, 2013.

The Preferred Units are entitled to annual cash distributions of 7.50% of the issue price, payable quarterly, which are subject to reset every five years. However, these quarterly cash distributions, during the first full eight quarters ending June 30, 2015, will accrue and accumulate, which we refer to as the Payment Deferral. Thus we will accrue, but not pay these amounts until the earlier of the fifth anniversary of the issuance of the Preferred Units or our redemption of the Preferred Units. The quarterly cash distribution for the three month period ended June 30, 2013 was prorated from May 8, 2013. The preferred unit distributions for the six month period ended June 30, 2014 were $45 million, all of which were deferred. On or after June 1, 2016, at the sole option of the holder of the Preferred Units, the Preferred Units may be converted into Class A Common Units, in whole or in part, at a conversion price of $27.78 per unit plus any accrued, accumulated and unpaid distributions, excluding the Payment Deferral, as adjusted for splits, combinations and unit distributions. At all other times, redemption of the Preferred Units, in whole or in part, is permitted only if: (1) we use the net proceeds from incurring debt and issuing equity, which includes asset sales, in equal amounts to redeem such Preferred Units; (2) a material change in the current tax treatment of the Preferred Units occurs; or (3) the rating agencies’ treatment of the equity credit for the Preferred Units is reduced by 50% or more, all at a redemption price of $25.00 per unit plus any accrued, accumulated and unpaid distributions, including the Payment Deferral.

 

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We issued the Preferred Units at a discount to the market price of the common units into which they are convertible. This discount totaling $47.7 million represents a beneficial conversion feature and is reflected as an increase in common and i-unit unitholders’ and General Partner’s capital and a decrease in Preferred Unitholders’ capital to reflect the fair value of the Preferred Units at issuance on our consolidated statement of partners’ capital for the six month period ended June 30, 2013. The beneficial conversion feature is considered a dividend and is distributed ratably from the issuance date of May 8, 2013, through the first conversion date, which is June 1, 2016, resulting in an increase in preferred capital and a decrease in common and subordinated unitholders’ capital. The impact of accretion of the beneficial conversion feature of $3.7 million and $7.3 million is also included in earnings per unit for the three and six month periods ended June 30, 2014, respectively.

We used the proceeds from the Preferred Unit issuance to repay commercial paper, to finance a portion of our capital expansion program relating to our core liquids and natural gas systems and for general partnership purposes.

Equity Distribution Agreement

In June 2010, we entered into an Equity Distribution Agreement, or EDA, for the issuance and sale from time to time of our Class A common units up to an aggregate amount of $150.0 million. On May 27, 2011, the Partnership entered into the Amended and Restated Equity Distribution Agreement, or Amended EDA, for the issuance and sale from time to time of our Class A common units up to an aggregate amount of $500.0 million from the execution date of the agreement through May 20, 2014. Under the EDA and Amended EDA, we sold 3,084,208 Class A common units, for aggregate gross proceeds of $124.8 million. No further sales were made under that agreement. The Amended EDA terminated in accordance with its terms on May 20, 2014.

Midcoast Energy Partner, L.P.

On November 13, 2013, MEP, one of our subsidiaries, completed its IPO of 18,500,000 Class A common units representing limited partner interests and subsequently issued an additional 2,775,000 Class A common units pursuant to the underwriter’s over allotment option. MEP received proceeds (net of underwriting discounts, structuring fees and offering expenses) of approximately $354.9 million. MEP used the net proceeds to distribute approximately $304.5 million to us, to pay approximately $3.4 million in revolving credit facility origination and commitment fees and used approximately $47.0 million to redeem 2,775,000 Class A common units from us. At June 30, 2014, we owned 5.9% of outstanding MEP Class A units, 100% of the outstanding MEP Subordinated Units, 100% of MEP’s general partner and 61% of the limited partner interests in Midcoast Operating.

On June 18, 2014, we agreed to sell a 12.6% limited partner interest in Midcoast Operating to MEP, for $350.0 million in cash, which brought our total ownership interest in Midcoast Operating to 48.4%. This transaction closed on July 1, 2014 and represents our first disposition of additional interests in Midcoast Operating since MEP’s IPO on November 13, 2013. We intend to sell additional interests in our natural gas assets, held through Midcoast Operating, to MEP and use the proceeds from any such sale as a source of funding for us. However, we do not know when, or if, any additional interests will be offered for sale.

Investments

In March and September 2013, Enbridge Management completed public offerings of 10,350,000 and 8,424,686 Listed Shares, respectively, representing limited liability company interests with limited voting rights, at a price to the underwriters of $26.44 and $28.02 per Listed Share, respectively. Enbridge Management received net proceeds of $272.9 million and $235.6 million for the March and September 2013 issuances, respectively, which we subsequently invested in an equal number of the Partnership’s i-units. We used the proceeds from our sale of i-units to finance a portion of our capital expansion program relating to the expansion of our core liquids and natural gas systems and for general corporate purposes.

 

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Available Credit

Our two primary sources of liquidity are provided by our commercial paper program and our Credit Facilities. We have a $1.5 billion commercial paper program that is supported by our Credit Facilities, which we access primarily to provide temporary financing for our operating activities, capital expenditures and acquisitions when the interest rates available to us for commercial paper are more favorable than the rates available under our Credit Facilities.

Credit Facilities

We have a committed senior unsecured revolving credit facility, which we refer to as the Credit Facility, that permits aggregate borrowings of up to, at any one time outstanding, $1.975 billion. The maturity date on the Credit Facility is September 26, 2018.

We also have a credit agreement, which we refer to as the 364-Day Credit Facility, that provided aggregate lending commitments of up to $1.2 billion: (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.

On July 3, 2014, we amended our 364-Day Credit Facility to extend the revolving credit termination date to July 3, 2015, and to decrease aggregate commitments under the facility by $550.0 million. After these changes, our 364-day Credit Facility now provides to us aggregate lending commitments of $650.0 million.

We refer to our Credit Facility and our 364-Day Credit Facility as the Credit Facilities, which provided an aggregate amount of approximately $3.2 billion of bank credit, as of June 30, 2014, 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. 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. Taking that policy into account, at June 30, 2014, we could borrow approximately $1.9 billion under the terms of our Credit Facilities, determined as follows:

 

     (in millions)  

Total credit available under Credit Facilities

   $ 3,175.0  

Less: Amounts outstanding under Credit Facilities

     —    

  Principal amount of commercial paper outstanding

     1,065.0  

  Letters of credit outstanding

     160.3  
  

 

 

 

Total amount we could borrow at June 30, 2014

   $ 1,949.7  
  

 

 

 

Individual London Inter-Bank Offered Rate, or LIBOR rate, borrowings under the terms of our Credit Facilities may be renewed as LIBOR rate borrowings or as base rate borrowings at the end of each LIBOR rate interest period, which is typically a period of three months or less. These renewals do not constitute new borrowings under the Credit Facilities and do not require any cash repayments or prepayments. For the three and six month periods ended June 30, 2014 and 2013, we did not have any LIBOR rate borrowings or base rate borrowings.

As of June 30, 2014, we were in compliance with the terms of all of our financial covenants under the Credit Facilities.

On February 3, 2014, we entered into an uncommitted letter of credit arrangement, pursuant to which the bank may, on a discretionary basis and with no commitment, agree to issue standby letters of credit upon our request in an aggregate amount not to exceed $200.0 million. While the letter of credit arrangement is

 

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uncommitted and issuance of letters of credit is at the bank’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.

Commercial Paper

We have a commercial paper program that 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. At June 30, 2014, we had approximately $1.1 billion in principal amount of commercial paper outstanding at a weighted average interest rate of 0.33%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net borrowings of approximately $765.0 million during the six month period ended June 30, 2014, which includes gross borrowings of $4.4 billion and gross repayments of $3.6 billion. At December 31, 2013, we had $300.0 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.37%, excluding the effect of our interest rate hedging activities. 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.

We have the ability and intent to refinance all of our commercial paper obligations on a long-term basis through borrowings under our Credit Facilities. Accordingly, such amounts have been classified as “Long-term debt” in our accompanying consolidated statements of financial position.

Senior Notes

All of our senior notes represent our unsecured obligations that rank equally in right of payment with all of our existing and future unsecured and unsubordinated indebtedness. Our senior notes are structurally subordinated to all existing and future indebtedness and other liabilities, including trade payables of our subsidiaries and the $200.0 million of senior notes issued by Enbridge Energy, Limited Partnership, or the OLP, which we refer to as the OLP Notes. The borrowings under our senior notes are non-recourse to our General Partner and Enbridge Management. All of our senior notes either pay or accrue interest semi-annually and have varying maturities and terms.

The OLP, our operating subsidiary that owns the Lakehead system, has $200.0 million of senior notes outstanding representing unsecured obligations that are structurally senior to our senior notes. The OLP Notes consist of $100.0 million of 7.000% senior notes due in 2018 and $100.0 million of 7.125% senior notes due in 2028. All of the OLP Notes pay interest semi-annually.

Junior Subordinated Notes

The $400.0 million in principal amount of our fixed/floating rate, junior subordinated notes due 2067, which we refer to as the Junior Notes, represent our unsecured obligations that are subordinate in right of payment to all of our existing and future senior indebtedness.

The Junior Notes do not restrict our ability to incur additional indebtedness. However, with limited exceptions, during any period we elect to defer interest payments on the Junior Notes, we cannot make cash distribution payments or liquidate any of our equity securities, nor can we or our subsidiaries make any principal and interest payments for any debt that ranks equally with or junior to the Junior Notes.

MEP Credit Agreement

On November 13, 2013, MEP, Midcoast Operating L.P., or Midcoast Operating, and their material domestic subsidiaries, entered into a senior revolving credit facility, which we refer to as the MEP Credit Agreement, that

 

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permits aggregate borrowings of up to, at any one time outstanding, $850.0 million. The original term of the MEP Credit Agreement is three years with an initial maturity date of November 2016, subject to four one-year requests for extensions. At June 30, 2014, MEP had $475.0 million in outstanding borrowings under the MEP Credit Agreement at a weighted average interest rate of 1.9%. Under the MEP Credit Agreement, MEP had net borrowings of approximately $140.0 million during the six month period ended June 30, 2014, which includes gross borrowings of $3.4 billion and gross repayments of $3.3 billion. At June 30, 2014, MEP was in compliance with the terms of its financial covenants.

Joint Funding Arrangements

In order to obtain the required capital to expand our various pipeline systems, we have determined that the required funding would challenge the Partnership’s ability to efficiently raise capital. Accordingly, we have explored numerous options and determined that several joint funding arrangements would provide the best source of available capital to fund the expansion projects.

Joint Funding Arrangement for Alberta Clipper Pipeline

In July 2009, we entered into a joint funding arrangement to finance the construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge. The Alberta Clipper Pipeline was mechanically complete in March 2010 and was ready for service on April 1, 2010.

In March 2010, we refinanced $324.6 million of amounts we had outstanding and payable to our General Partner under the A1 Credit Agreement by issuing a promissory note payable to our General Partner, which we refer to as the A1 Term Note. At such time we also terminated the A1 Credit Agreement. The A1 Term Note matures on March 15, 2020, bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400 million. The terms of the A1 Term Note are similar to the terms of our 5.20% senior notes due 2020, except that the A1 Term Note has recourse only to the assets of the United States portion of the Alberta Clipper Pipeline. Under the terms of the A1 Term Note, we have the ability to increase the principal amount outstanding to finance the debt portion of the investment our General Partner is obligated to make pursuant to the Alberta Clipper Joint Funding Arrangement to finance any additional costs associated with the construction of our portion of the Alberta Clipper Pipeline we incur after the date the original A1 Term Note was issued. The increases we make to the principal balance of the A1 Term Note will also mature on March 15, 2020. At June 30, 2014, we had approximately $312.0 million outstanding under the A1 Term Note.

Our General Partner made no equity contributions to the OLP during the six month periods ended June 30, 2014 and 2013, respectively, to fund its equity portion of the construction costs associated with Alberta Clipper Pipeline. The OLP paid a distribution of $12.8 million and $28.7 million to our General Partner and its affiliate during the six month periods ended June 30, 2014 and 2013, respectively, for their noncontrolling interest in the Series AC, representing limited partner ownership interests of the OLP that are specifically related to the assets, liabilities and operations of the Alberta Clipper Pipeline.

Joint Funding Arrangement for Eastern Access Projects

In May 2012, the OLP amended and restated its limited partnership agreement to establish an additional series of partnership interests, which we refer to as the EA interests. The EA interests were created to finance projects to increase access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as the Eastern Access Projects. From May 2012 through June 27, 2013, our General Partner indirectly owned 60% of all assets, liabilities and operations related to the Eastern Access Projects. On June 28, 2013, we and certain of our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding of the Eastern Access Projects from 40% to 25%. Additionally, within one year of the in-service date, currently scheduled for early 2016, we have the option to increase our economic interest by up to 15

 

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percentage points at cost. We received $90.2 million from our General Partner in consideration for our assignment to it of this portion of our interest, determined based on the capital we had funded prior to June 28, 2013 pursuant to Eastern Access Projects.

Our General Partner has made equity contributions totaling $360.8 million to the OLP during the six month period ended June 30, 2014 to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Joint Funding Arrangement for Mainline Expansion Projects

In December 2012, the OLP further amended and restated its limited partnership agreement to establish another series of partnership interests, which we refer to as the ME interests. The ME interests were created to finance 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, which we refer to as our Mainline Expansion Projects. From December 2012 through June 27, 2013, the projects were jointly funded by our General Partner at 60% and the Partnership at 40%, under the Mainline Expansion Joint Funding Agreement, which parallels the Eastern Access Joint Funding Agreement. On June 28, 2013, we and certain of our affiliates entered into an agreement with our General Partner pursuant to which we exercised our option to decrease our economic interest and funding in the project from 40% to 25%. Within one year of the last project in-service date, scheduled for early 2016, the Partnership will also have the option to increase its economic interest held at that time by up to 15 percentage points at cost. We received $12.0 million from our General Partner in consideration for our assignment to it of this portion of our interest, determined based on the capital we had funded prior to June 28, 2013 pursuant to the Mainline Expansion Projects.

Our General Partner has made equity contributions totaling $177.7 million and $59.5 to the OLP for the six month periods ended June 30, 2014 and 2013, respectively, to fund its equity portion of the construction costs associated with the Mainline Expansion Projects.

Midcoast Energy Partners, L.P.

On November 13, 2013, as part of the IPO, EEP conveyed a 39% interest in Midcoast Operating to MEP. On July 1, 2014 EEP sold an additional 12.6% interest in Midcoast Operating to MEP, which brought EEP’s total ownership interest in Midcoast Operating to 48.4%. Under the Midcoast Operating Agreement, EEP and MEP each have the option to contribute its proportionate share of additional capital to Midcoast Operating if any additional capital contributions are necessary to fund capital expenditures or other growth projects. To the extent that MEP or EEP elect not to make any such capital contributions, the contributing party will be permitted to make additional capital contributions in exchange for additional interests in Midcoast Operating. EEP can elect not to participate in certain growth projects. We expect to participate proportionately in these natural gas capital projects, although there is no guarantee that we will do so.

Sale of Accounts Receivable

Certain of our subsidiaries entered into a receivables purchase agreement, dated June 28, 2013, which we refer to as the Receivables Agreement, with an indirect wholly-owned subsidiary of Enbridge which was amended on September 20, 2013, and again on December 2, 2013. The Receivables Agreement and the transactions contemplated thereby were approved by the special committee of the board of directors of Enbridge Management. Pursuant to the Receivables Agreement, the Enbridge subsidiary will purchase on a monthly basis, for cash, current accounts receivable and accrued receivables, or the receivables, of the respective subsidiaries initially up to a monthly maximum of $450.0 million. The Receivables Agreement terminates on December 30, 2016.

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

 

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is recognized in “Operating and administrative-affiliate” expense in our consolidated statements of income. For the three and six month periods ended June 30, 2014, the cost stemming from the discount on the receivables sold was not material. For the three and six month periods ended June 30, 2014, we sold and derecognized $1,236.0 million and $2,532.7 million of receivables to the Enbridge subsidiary, respectively. For the three and six month periods ended June 30, 2014, the cash proceeds were $1,235.7 million and $2,532.1 million, respectively, which was remitted to the Partnership through our centralized treasury system. As of June 30, 2014, $408.1 million of the receivables were outstanding from customers that had not been collected on behalf of the Enbridge subsidiary.

As of June 30, 2014 and December 31, 2013, we have $33.3 million and $69.4 million, respectively, included in “Restricted cash” on our consolidated statements of financial position, consisting of cash collections related to the Receivables sold that have yet to be remitted to the Enbridge subsidiary as of June 30, 2014.

Cash Requirements

Capital Spending

We expect to make additional expenditures during the remainder of the year for the acquisition and construction of natural gas processing and crude oil transportation infrastructure. In 2014, we expect to spend approximately $1.7 billion on system enhancements and other projects associated with our liquids and natural gas systems with the expectation of realizing additional cash flows as projects are completed and placed into service. We expect to receive funding of approximately $1.2 billion from our General Partner based on our joint funding arrangement for the Eastern Access Projects and Mainline Expansion Projects and $145.0 million from MPC based on joint funding arrangement on the Sandpiper Project. We recognized capital expenditures of $1.1 billion for the six month period ending June 30, 2014, including $59.3 million on maintenance capital activities, $17.3 million in contributions to the Texas Express Pipeline and $612.9 million of expenditures that were financed by contributions from our General Partner and MPC via joint funding arrangements. At June 30, 2014, we had approximately $1.1 billion in outstanding purchase commitments, before contributions from our joint funding arrangements with our General Partner, attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment during 2014.

Acquisitions

We continue to assess ways to generate value for our unitholders, including reviewing opportunities that may lead to acquisitions or other strategic transactions, some of which may be material. We evaluate opportunities against operational, strategic and financial benchmarks before pursuing them. We expect to obtain the funds needed to make acquisitions through a combination of cash flows from operating activities, borrowings under our Credit Facilities and the issuance of additional debt and equity securities. All acquisitions are considered in the context of the practical financing constraints presented by the capital markets.

Forecasted Expenditures

We categorize our capital expenditures as either maintenance capital or enhancement expenditures. Maintenance capital expenditures are those expenditures that are necessary to maintain the service capability of our existing assets and include the replacement of system components and equipment which are worn, obsolete or completing its useful life. We also include a portion of our expenditures for connecting natural gas wells, or well-connects, to our natural gas gathering systems as maintenance capital expenditures. Enhancement expenditures include our capital expansion projects and other projects that improve the service capability of our existing assets, extend asset useful lives, increase capacities from existing levels, reduce costs or enhance revenues and enable us to respond to governmental regulations and developing industry standards.

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. The following table sets forth our estimates of capital expenditures we expect to make for system

 

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enhancement and maintenance capital for the year ending December 31, 2014. Although we anticipate making these expenditures in 2014, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, regulatory permitting, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets. For the full year ending December 31, 2014, we anticipate the capital expenditures to approximate the following:

 

     Total
Forecasted
Expenditures
 
     (in millions)  

Liquids Projects

  

Eastern Access Projects

   $ 930  

U.S. Mainline Expansions

     730  

Sandpiper

     390  

Line 6B 75-mile Replacement Program

     10  

Line 3 Replacement

     115  

Liquids Integrity Program

     335  

System Enhancements

     320  

Maintenance Capital Activities

     75  
  

 

 

 
     2,905  

Less joint funding from:

  

General Partner (1)

     1,245  

Third parties

     145  
  

 

 

 

Liquids Total

   $ 1,515  

Natural Gas Projects

  

Beckville Cryogenic Processing Plant

   $ 105  

System Enhancements

     180   

Maintenance Capital Activities

     60   
  

 

 

 
     345  

Less joint funding from:

  

MEP (2)

     160  
  

 

 

 

Natural Gas Total

     185  
  

 

 

 

TOTAL

   $ 1,700  
  

 

 

 

 

(1) 

No joint funding of the Line 3 Replacement is included in this line item as the joint funding agreement with Enbridge Inc. has not been finalized and approved by a special committee of independent directors of the board of EEP.

(2) 

Joint funding is based upon six months of MEP at a 39% ownership of Midcoast Operating and six months of MEP at a 51.6% ownership of Midcoast Operating.

We maintain a comprehensive integrity management program for our pipeline systems, which relies on the latest technologies that include internal pipeline inspection tools. These internal pipeline inspection tools identify internal and external corrosion, dents, cracking, stress corrosion cracking and combinations of these conditions. We regularly assess the integrity of our pipelines utilizing the latest generations of metal loss, caliper and crack detection internal pipeline inspection tools. We also conduct hydrostatic testing to determine the integrity of our pipeline systems. Accordingly, we incur substantial expenditures each year for our integrity management programs.

Under our capitalization policy, expenditures that replace major components of property or extend the useful lives of existing assets are capital in nature, while expenditures to inspect and test our pipelines are usually considered operating expenses. The capital spending components of our programs have increased over time as our pipeline systems age.

 

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We expect to incur continuing annual capital and operating expenditures for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems. Expenditure levels have continued to increase as pipelines age and require higher levels of inspection, maintenance and capital replacement. We also anticipate that maintenance capital will continue to increase due to the growth of our pipeline systems and the aging of portions of these systems. Maintenance capital expenditures are expected to be funded by operating cash flows.

We anticipate funding system enhancement capital expenditures temporarily through borrowing under the terms of our Credit Facility, with permanent debt and equity funding being obtained when appropriate.

Environmental

Lakehead Line 6B Crude Oil Release

During the six month period ended June 30, 2014, our cash flows were impacted by the approximate $65.0 million we paid for the environmental remediation, restoration and cleanup activities resulting from the crude oil releases that occurred in 2010 on Line 6B of our Lakehead system. We expect to pay the majority of the total remaining estimated cost of $224.5 million related to the Order received from the EPA during 2014.

In March 2013, we and Enbridge filed a lawsuit against the insurers of our remaining $145.0 million 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 assert that their payment is 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 during the third quarter 2013 and have since amended our lawsuit, such that it now includes only one carrier. While we believe that our claims for the remaining $103.0 million are covered under the policy, there can be no assurance that we will prevail in this lawsuit.

Derivative Activities

We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in commodity prices and interest rates and to reduce variability in our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on commodity prices or interest rates.

 

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The following table provides summarized information about the timing and expected settlement amounts of our outstanding commodity derivative financial instruments based upon the market values at June 30, 2014 for each of the indicated calendar years:

 

     Notional      2014     2015     2016     2017      2018      Total  
     (in millions)  

Swaps

                 

Natural gas (1)

     63,567,773      $ (0.7   $ (0.3   $ (0.1   $ —        $ —        $ (1.1

NGL (2)

     2,765,780        (5.2     (1.0     —         —          —          (6.2

Crude Oil (2)

     2,209,443        (6.1     1.8       0.2       —          —          (4.1

Options

                 

Natural gas—puts written (1)

     3,297,000        (0.1     (0.6     —         —          —          (0.7

Natural gas—puts purchased (1)

     7,870,000        0.1       1.0       0.4       —          —          1.5   

Natural gas—calls written (1)

     2,924,500        —         (0.2     (0.3     —          —          (0.5

Natural gas—calls purchased (1)

     1,277,500        —         0.2               0.2   

NGL—puts purchased (2)

     2,011,650        1.3       4.3       1.3       —          —          6.9   

NGL—calls purchased (2)

     46,000        0.1       —         —         —          —          0.1   

NGL—calls written (2)

     1,034,000        (0.6     (2.1     (1.8     —          —          (4.5

Crude Oil—puts purchased (2)

     986,700        —         1.2       1.5       —          —          2.7   

Crude Oil—calls written (2)

     986,700        —         (4.9     (3.4     —          —          (8.3

Forward contracts

                 

Natural gas (1)

     233,150,574        0.5       0.5       0.1       0.1        —          1.2   

NGL (2)

     20,891,067        5.1       1.2       —         —          —          6.3   

Crude Oil (2)

     999,242        (2.3     —         —         —          —          (2.3

Power (3)

     29,510        (0.2     —         —         —          —          (0.2
     

 

 

   

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

Totals

      $ (8.1   $ 1.1     $ (2.1   $ 0.1      $ —        $ (9.0
     

 

 

   

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

 

(1)

Notional amounts for natural gas are recorded in MMBtu.

(2)

Notional amounts for NGLs and crude oil are recorded in Barrels, or Bbl.

(3)

Notional amounts for power are recorded in Megawatt hours, or MWh.

The following table provides summarized information about the timing and estimated settlement amounts of our outstanding interest rate derivatives calculated based on implied forward rates in the yield curve at June 30, 2014 for each of the indicated calendar years:

 

      Notional
Amount
     2014     2015     2016     2017     2018      Thereafter      Total (1)  
     (in millions)  

Interest Rate Derivatives

                   

Interest Rate Swaps:

                   

Floating to Fixed

   $ 1,200.0      $ (4.2   $ (8.2   $ (5.1   $ (0.4   $ 0.1      $ —        $ (17.8

Pre-issuance hedges (2)

   $ 2,350.0        (242.3     —         25.6       —         —          —          (216.7
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 
      $ (246.5   $ (8.2   $ 20.5     $ (0.4   $ 0.1      $ —        $ (234.5
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

 

(1)

Fair values are presented in millions of dollars and exclude credit adjustments of approximately $3.4 million of gains at June 30, 2014.

(2)

Includes $3.3 million of cash collateral at June 30, 2014.

 

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Cash Flow Analysis

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

 

     For the six month
period ended June 30,
    Variance
2014 vs. 2013
Increase (Decrease)
 
         2014             2013        
     (in millions)  

Total cash provided by (used in):

      

Operating activities

   $ 359.6     $ 477.5     $ (117.9

Investing activities

     (1,287.0     (993.8     (293.2

Financing activities

     1,112.5       315.7       796.8  
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     185.1       (200.6     385.7  

Cash and cash equivalents at beginning of year

     164.8       227.9       (63.1
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 349.9     $ 27.3     $ 322.6  
  

 

 

   

 

 

   

 

 

 

Operating Activities

Net cash provided by our operating activities decreased $117.9 million for the six month period ended June 30, 2014 compared to the same period in 2013, primarily due to a decrease in our working capital accounts of $229.0 million. This decrease, due to our working capital accounts, was offset by a $212.2 million increase in net income offset by non-cash items of $101.1 million for the six month period ended June 30, 2014 as compared to the same period in 2013.

Changes in our working capital accounts are shown in the following table and discussed below:

 

     For the six  month
period ended June 30,
    Variance
2014 vs.  2013
 
         2014             2013        
     (in millions)  

Changes in operating assets and liabilities, net of acquisitions:

      

Receivables, trade and other

   $ 9.1     $ 60.1     $ (51.0

Due from General Partner and affiliates

     5.3       4.5       0.8  

Accrued receivables

     51.8       276.3       (224.5

Inventory

     (75.7     (95.1     19.4  

Current and long-term other assets

     (16.5     (19.1     2.6  

Due to General Partner and affiliates

     (6.0     18.4       (24.4

Accounts payable and other

     (63.8     (40.3     (23.5

Environmental liabilities

     (62.9     (32.7     (30.2

Accrued purchases

     (3.2     (95.3     92.1  

Interest payable

     1.4       4.1       (2.7

Property and other taxes payable

     (1.6     (14.0     12.4  
  

 

 

   

 

 

   

 

 

 

Net change in working capital accounts

   $ (162.1   $ 66.9     $ (229.0
  

 

 

   

 

 

   

 

 

 

The changes in our operating assets and liabilities, net of acquisitions as presented in our consolidated statements of cash flow for the six month period ended June 30, 2014, compared to the same period in 2013, is primarily the result of items listed below coupled with general timing differences for cash receipts and payment associated with our third-party accounts. The main items affecting our cash flows from operating assets and liabilities include the following:

 

   

The change in trade receivables from December 31, 2012 to June 30, 2013 was primarily due to the sale of $79.8 million of trade receivables to a subsidiary of Enbridge pursuant to the Receivables

 

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Agreement. This sale was partially offset by increased billings due to our Bakken projects entering service in March 2013 coupled with general timing differences in billing and receipt of payments. The change in trade receivables from December 31, 2013 to June 30, 2014 was primarily due to collecting $8.5 million more receivables than we sold for the six month period ended June 30, 2014 through the option to sale our trade receivables under the Receivables Agreement. For more information on the Receivables Agreement, refer to the discussion above Item 2. Liquidity and Capital ResourcesSale of Accounts Receivable;

 

   

The change in accrued receivables from December 31, 2012 to June 30, 2013 was primarily the result of lower production of natural gas and NGLs from our facilities during the six month period ended June 30, 2013. We sold $133.5 million of our accrued receivables under our Receivables Agreement. The decrease in accrued receivables from December 31, 2013 to June 30, 2014 was primarily due to lower prices and volumes of NGLs at our trucking and NGL marking business, partially offset by higher prices and volumes of natural gas and condensate for a net decrease of $41.8 million. In addition, we sold $16.2 million more receivables than we incurred for the six month period ended June 30, 2014 through the option to sale our accrued receivables under the Receivables Agreement. For more information on the Receivables Agreement, refer to the discussion above Item 2. Liquidity and Capital ResourcesSale of Accounts Receivable; and

 

   

The decline in accrued purchases from December 31, 2012 to June 30, 2013 was primarily the result of lower production of NGLs from our facilities during the month of June 2013 as compared with December 2012 due to some producers electing to retain ethane in the gas stream rather than to extract it.

The above decrease was partially offset by an increase in net income of $212.2 million offset by a $101.1 million decrease in our non-cash items for the six month period ended June 30, 2014 compared to the six month period ended June 30, 2013. The decrease in non-cash items primarily consisted of the following:

 

   

Decreased environmental costs of $141.7 million mainly attributed to $175.0 million in additional estimated costs recognized during 2013 related to the Line 6B crude oil release as a result of the Order accessed by the EPA in March 2013, while only $33.0 million in additional estimated costs were recognized in six month period ended June 30, 2013;

 

   

Increased derivative net losses of $47.0 million, compared to derivative net gains in 2013, primarily as a result of fluctuations in commodity prices;

 

   

Increased depreciation and amortization of $29.2 million due to projects placed in service in 2013;

 

   

Increased allowance for equity used during construction, or AEDC, of $17.4 million mainly due to the Eastern Access Projects; and

 

   

Decreased deferred and state income taxes for the three and six month periods ended June 30, 2014, of $11.9 million and $5.6 million, primarily due to the new Texas Margin Tax law passed in the second quarter of 2013 and an uncertain tax benefit adjustment for the 2012 tax year recorded in 2013, respectively.

Investing Activities

Net cash used in our investing activities during the six month period ended June 30, 2014 increased by $293.2 million, compared to the same period of 2013, primarily due to increased additions to property, plant and equipment, net of construction payables in 2014 related to various enhancement projects of $449.3 million, offset by the following:

 

   

Decreased restricted cash balance of $39.5 million consisting of cash collections related to the receivables sold that have yet to be remitted to the Enbridge subsidiary in accordance with the Receivables Agreement. For more information, refer to discussion above, Item 7. Liquidity and Capital ResourcesSale of Accounts Receivable; and

 

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Decreased cash contributions of $98.6 million combined with decreased allowance for interest during construction associated with our joint venture project, Texas Express NGL system, as the project went into service at the end of 2013, offset by $17.7 million in distributions in excess of cumulative earnings from our joint venture investment in the Texas Express NGL system.

Financing Activities

Net cash provided by our financing activities increased $796.8 million for the six month period ended June 30, 2014, compared to the same period in 2013, primarily due to the following:

 

   

Increased net borrowings on our commercial paper of $1,489.7 million for the six months ended June 30, 2014;

 

   

Increased capital contributions from noncontrolling interest in 2014 for ownership interests in the Mainline Expansion Projects, Eastern Access Projects and Sandpiper Project of $463.2 million;

 

   

Decreased repayments on long-term debt of $200.0 million for 2014, due to us repaying in full our 4.750% Senior Notes due in 2013 compared to no payments on our Senior Notes in 2014; and

 

   

Increased net borrowings on MEP’s Credit Agreement of $140.0 million in 2014 compared to no activity in 2013.

Offsetting the increases above were the following:

 

   

Decreased net proceeds in 2014 of $1,200.0 million due to no preferred unit issuances in 2014 while we had a preferred unit issuance in 2013 where we received $1,200.0 million in proceeds;

 

   

Decreased net proceeds from unit issuances, including our General Partner’s contributions of $278.7 million from 2013 while we had no issuances in 2014; and

 

   

Increased distributions to our limited partners of $3.6 million and distributions to noncontrolling interest of $13.8 million.

SUBSEQUENT EVENTS

364-Day Credit Facility

On July 3, 2014, we amended our 364-Day Credit Facility to extend the revolving credit termination date to July 3, 2015, and to decrease aggregate commitments under the facility by $550.0 million. After these changes, our 364-day Credit Facility now provides to us aggregate lending commitments of $650.0 million.

Equity Restructuring Transaction

Effective July 1, 2014, the General Partner entered into an equity restructuring transaction, or Equity Restructuring, with the Partnership in which the General Partner irrevocably waived its right to receive cash distributions and allocations of items of income, gain, deduction and loss in excess of 2% in respect of its general partner interest in the Previous IDRs, in exchange for the issuance to a wholly-owned subsidiary of the General Partner of (i) 66.1 million units of a new class of Partnership units designated as Class D Units, and (ii) 1,000 units of a new class of Partnership units designated as Incentive Distribution Units. The irrevocable waiver is effective with respect to the calendar quarter ending on June 30, 2014, and each calendar quarter thereafter. See Note 2. Net Income Per Limited Partner Unit.

In connection with the Equity Restructuring, effective July 1, 2014, we amended and restated our partnership agreement. The amendments among other changes and in conjunction with the waiver described above, effectively modified the distribution rights provided for by our partnership agreement to waive the Previous IDRs and to provide distribution rights to the new Class D Units and Incentive Distribution Units.

 

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These changes are discussed more fully in our Form 8-A/A filed with the SEC on July 1, 2014. Also, as part of the amendment to our partnership agreement, certain amendments were made to increase the Partnership’s flexibility to maintain and increase interim distributions to unitholders until current and future growth investments by the Partnership begin to generate cash and to enhance the Partnership’s ability to execute its long-term growth plans in a capital efficient and accretive manner.

Midcoast Energy Partners, L.P.

On June 18, 2014, we agreed to sell a 12.6% limited partner interest in Midcoast Operating to MEP, for $350.0 million in cash, which will bring EEP’s total ownership interest in Midcoast Operating to 48.4%. This transaction closed on July 1, 2014, and represents EEP’s first disposition of additional interests in Midcoast Operating since MEP’s initial public offering on November 13, 2013. See Note 7. Partner’s Capital

Distribution to Partners

On July 31, 2014, the board of directors of Enbridge Management declared a distribution payable to our partners on August 14, 2014. The distribution will be paid to unitholders of record as of August 7, 2014 of our available cash of $224.7 million at June 30, 2014, or $0.5550 per limited partner unit. Of this distribution, $187.3 million will be paid in cash, $36.7 million will be distributed in i-units to our i-unitholder, Enbridge Management, and due to the i-unit distribution, $0.8 million will be retained from our General Partner from amounts otherwise distributable to it in respect of its general partner interest and limited partner interest to maintain its 2% general partner interest.

Distribution to Series AC Interests

On July 31, 2014, 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 a holder of the Series AC interests, declared a distribution payable to the holders of the Series AC general and limited partner interests. The OLP will pay $14.8 million to the noncontrolling interest in the Series AC, while $7.4 million will be paid to us.

Distribution to Series EA Interests

On July 31, 2014, 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 a holder of the Series EA interests, declared a distribution payable to the holders of the Series EA general and limited partner interests. The OLP will pay $16.7 million to the noncontrolling interest in the Series EA, while $5.6 million will be paid to us.

Distribution from MEP

On July 31, 2014, the board of directors of Midcoast Holdings, L.L.C., acting in its capacity as the general partner of MEP, declared a cash distribution payable to their partners on August 14, 2014. The distribution will be paid to unitholders of record as of August 7, 2014, of MEP’s available cash of $15.0 million at June 30, 2014, or $0.3250 per limited partner unit. MEP will pay $6.9 million to their public Class A common unitholders, while $8.1 million in the aggregate will be paid to us with respect to our Class A common units, subordinated units and to Midcoast Holdings, L.L.C. with respect to its general partner interest.

Midcoast Operating Distribution

On July 31, 2014, the general partner of Midcoast Operating, acting in its capacity as the general partner of Midcoast Operating, declared a cash distribution by Midcoast Operating payable to its partners of record as of August 7, 2014. Midcoast Operating will pay $22.0 million to us and $23.5 million to MEP.

 

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REGULATORY MATTERS

FERC Transportation Tariffs

Lakehead System

Effective April 1, 2013, we filed our Lakehead system annual tariff rate adjustment with the FERC to reflect our projected costs and throughput for 2013 and true-ups for the difference between estimated and actual costs and throughput data for the prior year. This tariff rate adjustment filing also included the recovery of costs related to the Flanagan Tank Replacement Project and the Eastern Access Phase 1 Mainline Expansion Project. The Lakehead system utilizes the System Expansion Project II and the Facility Surcharge Mechanism, or FSM, which are components of our Lakehead system’s overall rate structure and allows for the recovery of costs for enhancements or modifications to our Lakehead system.

This tariff filing increased the transportation rate for heavy crude oil movements from the Canadian border to the Chicago, Illinois area by approximately $0.28 per barrel, to approximately $2.13 per barrel. The surcharge is applicable to each barrel of crude oil that is placed on our system beginning on the effective date of the tariff, which we recognize as revenue when the barrels are delivered, typically a period of approximately 30 days from the date shipped.

On June 27, 2014, we filed for an increase to our Lakehead system rates. These rates have an effective date of August 1, 2014. This tariff filing was in part an index filing in accordance with 18 C.F.R.342.3 and in part a compliance filing with certain settlement agreements, which are not subject to FERC indexing. This filing included the increase in rates in compliance with the indexed rate ceilings allowed by the FERC which incorporates the multiplier of 1.038858, which was issued by the FERC on May 14, 2014, in Docket No. RM93-11-000. This filing also reflected our annual tariff rate adjustment for the FSM components or our Lakehead systems’ overall rate structure, as described above. As part of this rate structure our rates reflect our projected costs for 2014 and true-ups for the difference between estimated and actual costs for the prior year. Historically, we have made the Lakehead system annual tariff rate adjustment for the FSM component of rates with an effective date of April 1 and the index rate filing with an effective date of July 1, however, the filings were delayed as we were in negotiations with the Canadian Association of Petroleum Producers, or CAPP, concerning certain components of the tariff rate structure. This negotiation eliminates the SEPII surcharge and added to the FSM component of rates recovery of costs for Line 14, which is virtually the entire asset base associated with the SEPII expansion. The recent negotiation also provides for the recovery of Agreed-Upon Legacy Integrity and Agreed-Upon Future Integrity. These elements are a portion of the costs incurred by the partnership to maintain the integrity and safety of the pipeline systems. The rates also include recovery of costs related to Eastern Access Phase 2 Mainline Expansion and the 2014 Mainline Expansions.

This tariff filing increased the transportation rate for heavy crude oil movements from the Canadian border to the Chicago, Illinois area by approximately $0.32 per barrel, to approximately $2.49 per barrel. The surcharge is applicable to each barrel of crude oil that is placed on our system beginning on the effective date of the tariff, which we recognize as revenue when the barrels are delivered, typically a period of approximately 30 days from the date shipped.

North Dakota and Ozark Systems

Effective April 1, 2013 for the North Dakota system we filed updates to the calculation of the surcharges on the two previously approve expansion, Phase 5 Looping and Phase 6 Mainline, on our North Dakota system. These expansions are cost-of-service based surcharges that are trued up each year to actual costs and volumes and are not subject to the FERC indexing methodology. This filing increased the average transportation rate for crude oil movements on our North Dakota System by $0.55 per barrel, to an average of approximately $2.06 per barrel.

Effective July 1, 2013, we filed FERC tariffs for our ,North Dakota and Ozark systems. We increased the rates in compliance with the indexed rate ceilings allowed by FERC which incorporates the multiplier of 1.045923, which was issued by FERC on May 15, 2013, in Docket No. RM93-11-000.

 

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Effective April 1, 2014, we filed updates to the calculation of the surcharges on the two previously approved expansions, Phase 5 Looping and Phase 6 Mainline, on our North Dakota system. As previously mentioned these expansions are cost-of-service based surcharges that are trued up each year to actual costs and volumes and are not subject to the FERC indexing methodology. The filing increased transportation rates for all crude oil movements on our North Dakota system with a destination of Clearbrook, Minnesota by an average of approximately $0.09 per barrel, to an average of approximately $2.21 per barrel.

On May 30, 2014, we filed FERC tariffs with effective dates of July 1, 2014 for our North Dakota and Ozark systems. We increased the rates in compliance with the indexed rate ceilings allowed by the FERC which incorporates the multiplier of 1.038858, which was issued by the FERC on May 14, 2014, in Docket No. RM93-11-000.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with the information presented in our Annual Report on Form 10-K for the year ended December 31, 2013, in addition to information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There have been no material changes to that information other than as presented below.

Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations 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 cost of natural gas 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 (i.e., 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 of our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices.

 

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Interest Rate Derivatives

The table below provides information about our derivative financial instruments that we use to hedge the interest payments on our variable rate debt obligations that are sensitive to changes in interest rates and to lock in the interest rate on anticipated issuances of debt in the future. For interest rate swaps, the table presents notional amounts, the rates charged on the underlying notional amounts and weighted average interest rates paid by expected maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contract. Weighted average variable rates are based on implied forward rates in the yield curve at June 30, 2014.

 

                          Fair Value (2) at  

Date of Maturity & Contract Type

   Accounting
Treatment
     Notional      Average Fixed
Rate (1)
    June 30,
2014
    December 31,
2013
 
            (dollars in millions)  

Contracts maturing in 2015

            

Interest Rate Swaps—Pay Fixed

     Cash Flow Hedge       $ 300        2.43   $ (3.6   $ (6.8 )  

Contracts maturing in 2017

            

Interest Rate Swaps—Pay Fixed

     Cash Flow Hedge       $ 400        2.21   $ (14.4   $ (13.8 )  

Contracts maturing in 2018

            

Interest Rate Swaps—Pay Fixed

     Cash Flow Hedge       $ 500        2.08   $ 0.2     $ 3.3   

Contracts settling prior to maturity

            

2014—Pre-issuance Hedges (3)

     Cash Flow Hedge       $ 1,850        4.27   $ (242.3   $ (132.7 ) 

2016—Pre-issuance Hedges

     Cash Flow Hedge       $ 500        2.87   $ 25.6     $ 60.8   

 

(1)

Interest rate derivative contracts are based on the one-month or three-month London Interbank Offered Rate, or LIBOR.

(2)

The fair value is determined from quoted market prices at June 30, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $3.4 million of gains at June 30, 2014 and $7.1 million of losses at December 31, 2013.

(3)

Includes $3.3 million and $16.7 million of cash collateral at June 30, 2014 and December 31, 2013, respectively.

 

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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 June 30, 2014 and December 31, 2013.

 

     At June 30, 2014     At December 31, 2013  
                Wtd. Average
Price (2)
     Fair Value (3)     Fair Value (3)  
     Commodity   Notional (1)      Receive      Pay      Asset      Liability     Asset      Liability  
                              (in millions)  

Portion of contracts maturing in 2014

                     

Swaps

                     

Receive variable/pay fixed

   Natural Gas     832,732       $ 4.41      $ 4.36       $ 0.1      $ —        $ —        $ —     
   NGL     316,000       $ 62.97      $ 60.27       $ 0.9      $ —        $ 0.6      $ (0.4

Receive fixed/pay variable

   Natural Gas     3,631,800       $ 4.32      $ 4.42       $ 0.3      $ (0.7   $ 0.1      $ (1.0
   NGL     1,612,280       $ 54.87      $ 58.63       $ 1.0      $ (7.1   $ 4.8      $ (12.7
   Crude Oil     725,528       $ 94.78      $ 103.18       $ —        $ (6.1   $ 3.4      $ (5.4

Receive variable/pay variable

   Natural Gas     32,675,300       $ 4.37      $ 4.38       $ 0.7      $ (1.1   $ 0.6      $ (0.1

Physical Contracts

                     

Receive variable/pay fixed

   Natural Gas     79,594       $ 4.36      $ 4.36       $ —        $ —        $ —        $ —     
   NGL     1,355,000       $ 35.27      $ 34.13       $ 1.6      $ (0.1   $ 0.9      $ (0.9
   Crude Oil     81,000       $ 105.17      $ 107.05       $ —        $ (0.1   $ —        $ —     

Receive fixed/pay variable

   Natural Gas     333,893       $ 4.41      $ 4.40       $ —        $ —        $ —        $ —     
   NGL     2,403,278       $ 37.70      $ 38.51       $ 0.5      $ (2.5   $ 0.4      $ (2.6
   Crude Oil     184,000       $ 103.96      $ 104.85       $ 0.2      $ (0.3   $ —        $ (0.4

Pay fixed

   Power (4)     29,510       $ 39.57      $ 46.58       $ —        $ (0.2   $ —        $ (0.7

Receive variable/pay variable

   Natural Gas     107,169,373       $ 4.41      $ 4.40       $ 1.3      $ (0.8   $ 0.9      $ (0.4
   NGL     13,859,812       $ 48.43      $ 48.03       $ 6.4      $ (0.8   $ 5.8      $ (3.7
   Crude Oil     734,242       $ 101.94      $ 104.89       $ 0.8      $ (2.9   $ 1.1      $ (1.2

Portion of contracts maturing in 2015

                     

Swaps

                     

Receive variable/pay fixed

   Natural Gas     19,080       $ 4.47      $ 4.54       $ —        $ —        $ —        $ —     
   NGL     82,500       $ 83.98      $ 84.84       $ —        $ (0.1   $ —        $ —     
   Crude Oil     456,000       $ 96.90      $ 92.94       $ 1.8      $ —        $ —        $ —     

Receive fixed/pay variable

   Natural Gas     596,861       $ 4.74      $ 4.51       $ 0.1      $ —        $ —        $ —     
   NGL     755,000       $ 53.11      $ 54.33       $ 0.9      $ (1.8   $ 1.5      $ (1.1
   Crude Oil     959,665       $ 97.20      $ 97.13       $ 2.4      $ (2.4   $ 8.3      $ —     

Receive variable/pay variable

   Natural Gas     19,885,000       $ 4.29      $ 4.31       $ 0.3      $ (0.7   $ 0.1      $ —     

Physical Contracts

                     

Receive fixed/pay variable

   NGL     295,624       $ 53.31      $ 54.03       $ 0.1      $ (0.3   $ —        $ —     

Receive variable/pay variable

   Natural Gas     79,446,592       $ 4.29      $ 4.29       $ 1.3      $ (0.8   $ 0.5      $ (0.1
   NGL     2,977,353       $ 66.95      $ 66.50       $ 1.9      $ (0.5   $ —        $ —     

Portion of contracts maturing in 2016

                     

Swaps

                     

Receive fixed/pay variable

   Crude Oil     —         $ —        $ —         $ —        $ —        $ 0.7      $ —     

Receive variable/pay fixed

   Crude Oil     68,250       $ 92.49      $ 90.00       $ 0.2      $ —        $ —        $ —     

Receive variable/pay variable

   Natural Gas     5,927,000       $ 4.09      $ 4.11       $ —        $ (0.1   $ —        $ —     

Physical Contracts

                     

Receive variable/pay variable

   Natural Gas     32,721,379       $ 4.16      $ 4.16       $ 0.7      $ (0.6   $ 0.1      $ —     

Portion of contracts maturing in 2017

                     

Physical Contracts

                     

Receive variable/pay variable

   Natural Gas     13,399,743       $ 4.38      $ 4.36       $ 0.2      $ (0.1   $ —        $ —     

 

(1)

Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl. Our power purchase agreements are measured in MWh.

(2)

Weighted average prices received and paid are in $/MMBtu for natural gas, $/Bbl for NGL and crude oil and $/MWh for power.

(3)

The fair value is determined based on quoted market prices at June 30, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.1 million of losses and $0.1 million of gains at June 30, 2014 and December 31, 2013, respectively.

(4)

For physical power, the receive price shown represents the index price used for valuation purposes.

 

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The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at June 30, 2014 and December 31, 2013.

 

    

At June 30, 2014

    At December 31, 2013  
    

Commodity

   Notional  (1)      Strike
Price (2)
     Market
Price (2)
     Fair Value (3)     Fair Value (3)  
                 Asset      Liability     Asset      Liability  
                               (in millions)  

Portion of option contracts maturing in 2014

  

                

Puts (purchased)

   Natural Gas      2,208,000       $ 3.90       $ 4.46       $ 0.1      $ —        $ 0.7      $ —     
   NGL      386,400       $ 54.79       $ 56.17       $ 1.3      $ —        $ 2.9      $ —     

Calls (written)

   NGL      230,000       $ 60.92       $ 58.65       $ —        $ (0.6   $ —        $ (1.0

Puts (written)

   Natural Gas      1,472,000       $ 3.90       $ 4.46       $ —        $ (0.1   $ —        $ (0.5

Calls (purchased)

   NGL      46,000       $ 50.40       $ 45.50       $ 0.1      $ —        $ —        $ —     

Portion of option contracts maturing in 2015

  

                

Puts (purchased)

   Natural Gas      4,015,000       $ 3.90       $ 4.22       $ 1.0      $ —        $ 1.7      $ —     
   NGL      1,259,250       $ 49.40       $ 54.10       $ 4.3      $ —        $ 6.0      $ —     
   Crude Oil      547,500       $ 85.42       $ 96.40       $ 1.2      $ —        $ 1.8      $ —     

Calls (written)

   Natural Gas      1,277,500       $ 5.05       $ 4.22       $ —        $ (0.2   $ —        $ (0.3
   NGL      438,000       $ 57.05       $ 54.83       $ —        $ (2.1   $ —        $ (1.0
   Crude Oil      547,500       $ 91.75       $ 96.40       $ —        $ (4.9   $ —        $ (1.9

Puts (written)

   Natural Gas      1,825,000       $ 4.08       $ 4.22       $ —        $ (0.6   $ —        $ —     

Calls (purchased)

   Natural Gas      1,277,500       $ 5.05       $ 4.22       $ 0.2      $ —        $ —        $ —     

Portion of option contracts maturing in 2016

  

                

Puts (purchased)

   Natural Gas      1,647,000       $ 3.75       $ 4.24       $ 0.4      $ —        $ —        $ —     
   NGL      366,000       $ 38.22       $ 43.67       $ 1.3      $ —        $ —        $ —     
   Crude Oil      439,200       $ 80.00       $ 91.25       $ 1.5      $ —        $ —        $ —     

Calls (written)

   Natural Gas      1,647,000       $ 4.98       $ 4.24       $ —        $ (0.3   $ —        $ —     
   NGL      366,000       $ 47.02       $ 43.67       $ —        $ (1.8   $ —        $ —     
   Crude Oil      439,200       $ 92.25       $ 91.25       $ —        $ (3.4   $ —        $ —     

 

(1)

Volumes of natural gas are measured in MMBtu, whereas volumes of NGL and crude oil are measured in Bbl.

(2)

Strike and market prices are in $/MMBtu for natural gas and in $/Bbl for NGL and crude oil.

(3)

The fair value is determined based on quoted market prices at June 30, 2014 and December 31, 2013, respectively, discounted using the swap rate for the respective periods to consider the time value of money. Fair values are presented in millions of dollars and exclude credit valuation adjustments of approximately $0.1 million of gains at June 30, 2014.

Our credit exposure for over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contract. When appropriate, valuations are adjusted for various factors such as credit and liquidity considerations.

 

     June 30,
2014
    December 31,
2013
 
     (in millions)  

Counterparty Credit Quality (1)

    

AAA

   $ 0.2     $ 0.3  

AA

     (97.5     (49.7

(2)

     (145.9     (40.1

Lower than A

     3.2       0.8  
  

 

 

   

 

 

 
   $ (240.0   $ (88.7
  

 

 

   

 

 

 

 

(1) 

As determined by nationally-recognized statistical ratings organizations.

(2) 

Includes $3.3 million and $16.7 million of cash collateral at June 30, 2014 and December 31, 2013, respectively.

 

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Item 4. Controls and Procedures

We and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, or the Exchange Act, within the time periods specified in the rules and forms of the Securities and Exchange Commission, and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our principal executive and principal financial officers, has evaluated the effectiveness of our disclosure controls and procedures as of June 30, 2014. Based upon that evaluation, our principal executive and principal financial officers concluded that our disclosure controls and procedures are effective at the reasonable assurance level. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting and other services on our behalf.

There have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting during the three month period ended June 30, 2014.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

Refer to Part I, Item 1. Financial Statements, “Note 9. Commitments and Contingencies,” which is incorporated herein by reference.

Item 1A. Risk Factors

There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2013.

Item 6. Exhibits

Reference is made to the “Index of Exhibits” following the signature page, which we hereby incorporate into this Item.

 

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SIGNATURES

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

 

 

ENBRIDGE ENERGY PARTNERS, L.P.

(Registrant)

  By:   Enbridge Energy Management, L.L.C.
   

as delegate of Enbridge Energy Company, Inc.

as General Partner

Date: August 1, 2014   By:  

/s/ Mark A. Maki

   

Mark A. Maki

President and

Principal Executive Officer

Date: August 1, 2014   By:  

/s/ Stephen J. Neyland

   

Stephen J. Neyland

Vice President—Finance

(Principal Financial Officer)

 

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Index of Exhibits

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

 

Exhibit
Number
  

Description

3.1    Sixth Amended and Restated Agreement of Limited Partnership of Enbridge Energy Partners, L.P., dated as of June 18, 2014 (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K, filed on June 19, 2014).
10.1    Irrevocable Waiver dated as of June 18, 2014, made by Enbridge Energy Company, Inc. (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed on June 19, 2014).
10.2    Purchase and Sale Agreement by and between Enbridge Energy Partners, L.P. and Midcoast Energy Partners, L.P., dated as of June 18, 2014 (incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, filed on July 19, 2014).
10.3    Amendment No. 5 to Credit Agreement and Extension and Decrease Agreement, dated as of July 3, 2014, by and among Enbridge Energy Partners, L.P., the lenders parties thereto and JPMorgan Chase Bank, National Association (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, filed on July 8, 2014).
31.1*    Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2*    Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1*    Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2*    Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*    XBRL Instance Document.
101.SCH*    XBRL Taxonomy Extension Schema Document.
101.CAL*    XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*    XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*    XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*    XBRL Taxonomy Extension Presentation Linkbase Document.

 

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