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ENBRIDGE ENERGY PARTNERS LP 10-Q 2011

Documents found in this filing:

  1. 10-Q
  2. Ex-31.1
  3. Ex-31.2
  4. Ex-32.1
  5. Ex-32.2
  6. 10-Q
  7. 10-Q
FORM 10-Q
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, 2011

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, TX 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 ¨   Smaller reporting company ¨
(Do not check if a 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 219,517,198 Class A common units outstanding as of July 29, 2011.

 

 

 

 


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, 2011 and 2010

     1   
  

Consolidated Statements of Comprehensive Income for the three and six month periods ended June 30, 2011 and 2010

     2   
  

Consolidated Statements of Cash Flows for the six month periods ended June 30, 2011 and 2010

     3   
  

Consolidated Statements of Financial Position as of June 30, 2011 and December 31, 2010

     4   
  

Notes to the Consolidated Financial Statements

     5   

Item 2.

  

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

     34   

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

     56   

Item 4.

  

Controls and Procedures

     60   
   PART II - OTHER INFORMATION   

Item 1.

  

Legal Proceedings

     61   

Item 1A.

  

Risk Factors

     61   

Item 6.

  

Exhibits

     61   

Signatures

     62   

Exhibits

     63   

In this report, unless the context requires otherwise, references to “we,” “us,” “our” 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 contains forward-looking statements, which are typically identified by words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “project,” “strategy,” “target,” “could,” “should” or “will” and similar words or statements, express or implied, suggesting future outcomes or statements regarding an outlook or the negative of those terms. Although we believe that these forward-looking statements are reasonable based on the information available on the dates these statements are made and processes used to prepare the information, these statements are not guarantees of future performance, and we caution you not to place undue reliance on these statements. By their nature, these statements involve a variety of assumptions, unknown risks, uncertainties and other factors, which may cause actual results, levels of activity and performance to differ materially from those expressed or implied by these statements. Material assumptions may include, among others, the expected supply of and demand for crude oil, natural gas and natural gas liquids, or NGLs; prices of crude oil, natural gas and NGLs; inflation and interest rates; operational reliability; and weather.

Our forward-looking statements are subject to risks and uncertainties pertaining to operating performance, regulatory parameters, weather, economic conditions, interest rates and commodity prices, including but not limited to, those risks and uncertainties discussed in this Quarterly Report on Form 10-Q and our other reports that we have filed or will file with the Securities and Exchange Commission, or SEC. The impact of any one risk, uncertainty or factor on a particular forward-looking statement is not determinable with certainty as these factors are interdependent, and our future course of action depends on the assessment of all information available at the relevant time by those responsible for the management of our operations. Except to the extent required by law, we assume no obligation to publicly update or revise any forward-looking statements made herein whether as a result of new information, future events or otherwise. All subsequent forward-looking statements, whether written or oral, attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements and, as such, may be updated in our future filings with the SEC. For additional discussion of risks, uncertainties and assumptions, see “Item 1A. Risk Factors” included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

 

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Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF INCOME

 

     For the three month
period ended June 30,
    For the six month
period ended June 30,
 
     2011     2010     2011     2010  
     (unaudited; in millions, except per unit amounts)  

Operating revenue (Note 10)

   $ 2,372.0      $ 1,747.4      $ 4,660.9      $ 3,678.6   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses

        

Cost of natural gas (Notes 4 and 10)

     1,861.3        1,270.4        3,690.8        2,794.6   

Environmental costs, net of recoveries (Notes 1 and 9)

     23.3        (0.1     (11.3     4.5   

Oil measurement adjustments (Notes 1 and 12)

     (54.1     1.1        (58.7       

Operating and administrative (Note 1)

     167.6        135.3        334.7        267.8   

Power (Note 10)

     33.9        36.5        69.5        68.8   

Depreciation and amortization (Note 5)

     89.6        77.6        178.0        145.5   
  

 

 

   

 

 

   

 

 

   

 

 

 
     2,121.6        1,520.8        4,203.0        3,281.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     250.4        226.6        457.9        397.4   

Interest expense (Notes 6 and 10)

     78.5        69.6        157.9        128.9   

Other income (expense) (Notes 9 and 14)

            (0.1     6.0        16.7   
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

     171.9        156.9        306.0        285.2   

Income tax expense (Note 11)

     0.9        2.4        3.2        4.6   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     171.0        154.5        302.8        280.6   

Less: Net income attributable to noncontrolling interest (Note 8)

     14.1        14.5        28.8        25.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 156.9      $ 140.0      $ 274.0      $ 255.4   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income allocable to limited partner interests

   $ 130.3      $ 120.3      $ 227.0      $ 219.5   
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income per limited partner unit (basic and diluted) (Note 2)

   $ 0.51      $ 0.51      $ 0.90      $ 0.93   
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average limited partner units outstanding

     255.2        236.5        254.0        236.2   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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

 

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

     For the three month
period ended June 30,
    For the six month
period ended June 30,
 
         2011             2010             2011             2010      
     (unaudited; in millions)  

Net income

   $ 171.0      $ 154.5      $ 302.8      $ 280.6   

Other comprehensive income (loss), net of tax expense of $0.6, $0.2, $0.1 and $0.4, respectively (Note 10)

     (3.7     (52.9     (61.1     (46.4
                                

Comprehensive income

     167.3        101.6        241.7        234.2   

Less: Comprehensive income attributable to noncontrolling interest (Note 8)

     14.1        14.5        28.8        25.2   
                                

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

   $ 153.2      $ 87.1      $ 212.9      $ 209.0   
                                

 

 

 

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

 

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     For the six month period ended June 30,  
         2011             2010      
     (unaudited; in millions)  

Cash provided by operating activities

    

Net income

   $ 302.8      $ 280.6   

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

    

Depreciation and amortization (Note 5)

     178.0        145.5   

Derivative fair value net gains (Note 10)

     (3.3     (25.9

Inventory market price adjustments (Note 4)

     0.2        2.6   

Environmental costs, net of recoveries (Notes 1 and 9)

     24.0        4.3   

Oil measurement adjustments (Notes 1 and 12)

     (52.2       

Other (Notes 1 and 16)

     7.2        (5.7

Changes in operating assets and liabilities, net of acquisitions:

    

Receivables, trade and other (Note 9)

     (32.0     37.7   

Due from General Partner and affiliates

     4.7        (17.4

Accrued receivables

     102.4        15.0   

Inventory (Note 4)

     (3.5     (58.2

Current and long-term other assets (Note 10)

     1.5        (0.9

Due to General Partner and affiliates (Note 8)

     27.8        18.7   

Accounts payable and other (Notes 1, 3 and 10)

     23.0        1.1   

Environmental liabilities (Notes 1 and 9)

     (105.3     (4.9

Accrued purchases

     (12.9     (20.1

Interest payable

     (0.1     8.7   

Property and other taxes payable

     (1.3     (2.5

Settlement of interest rate derivatives (Note 10)

            (13.2
                

Net cash provided by operating activities

     461.0        365.4   
                

Cash used in investing activities

    

Additions to property, plant and equipment (Notes 5 and 9)

     (363.1     (356.2

Changes in construction payables

     (8.3     (9.9

Asset acquisitions

     (27.2     (17.0

Other

     (7.8       
                

Net cash used in investing activities

     (406.4     (383.1
                

Cash (used in) provided by financing activities

    

Net proceeds from unit issuances (Note 7)

     74.4        15.1   

Distributions to partners (Note 7)

     (265.2     (233.0

Repayments to General Partner (Note 8)

     (6.4     (324.6

Net proceeds from issuances of long-term debt (Note 6)

            496.1   

Net borrowings (repayments) under Credit Facility (Note 6)

     75.0        (765.0

Net commercial paper borrowings (Note 6)

     115.1        409.9   

Borrowings from General Partner (Note 8)

     7.0        395.8   

Contribution from noncontrolling interest (Note 8)

     3.3        87.0   

Distributions to noncontrolling interest (Note 8)

     (43.4       
                

Net cash (used in) provided by financing activities

     (40.2     81.3   
                

Net increase in cash and cash equivalents

     14.4        63.6   

Cash and cash equivalents at beginning of year

     144.9        143.6   
                

Cash and cash equivalents at end of period

   $ 159.3      $ 207.2   
                

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

 

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF FINANCIAL POSITION

 

       June 30,  
2011
      December 31,  
2010
 
     (unaudited; dollars in millions)  
ASSETS     

Current assets

    

Cash and cash equivalents (Note 3)

   $ 159.3      $ 144.9   

Receivables, trade and other, net of allowance for doubtful accounts of $1.9 in 2011 and $1.8 in 2010 (Note 9)

     247.0        171.2   

Due from General Partner and affiliates

     22.4        27.1   

Accrued receivables

     580.1        683.7   

Inventory (Note 4)

     138.0        134.7   

Other current assets (Note 10)

     42.8        58.3   
                
     1,189.6        1,219.9   

Property, plant and equipment, net (Notes 5, 9 and 14)

     8,859.8        8,641.6   

Goodwill

     246.7        246.7   

Intangibles, net

     270.8        276.4   

Other assets, net (Note 10)

     63.6        56.4   
                
   $ 10,630.5      $ 10,441.0   
                
LIABILITIES AND PARTNERS’ CAPITAL     

Current liabilities

    

Due to General Partner and affiliates

   $ 78.7      $ 53.3   

Accounts payable and other (Notes 3 and 10)

     318.2        289.2   

Environmental liabilities (Note 9)

     122.5        227.0   

Accrued purchases

     592.8        596.4   

Interest payable

     60.2        60.3   

Property and other taxes payable

     47.8        49.1   

Note payable to General Partner (Note 8)

     12.0        11.6   

Current maturities of long-term debt (Note 6)

     31.0        31.0   
                
     1,263.2        1,317.9   

Long-term debt (Note 6)

     4,969.3        4,778.9   

Note payable to General Partner (Note 8)

     336.0        335.8   

Other long-term liabilities (Notes 9 and 10)

     164.1        122.9   
                
     6,732.6        6,555.5   
                

Commitments and contingencies (Note 9)

    

Partners’ capital (Notes 7 and 8)

    

Class A common units (211,467,198 and 209,084,106 at June 30, 2011 and December 31, 2010, respectively)

     2,683.4        2,641.0   

Class B common units (7,825,500 at June 30, 2011 and December 31, 2010)

     65.9        64.9   

i-units (36,410,356 and 35,285,422 at June 30, 2011 and December 31, 2010, respectively)

     617.2        579.1   

General Partner

     260.1        256.8   

Accumulated other comprehensive income (loss) (Note 10)

     (182.8     (121.7
                

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

     3,443.8        3,420.1   

Noncontrolling interest (Note 8)

     454.1        465.4   
                

Total partners’ capital

     3,897.9        3,885.5   
                
   $ 10,630.5      $ 10,441.0   
                

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

 

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Table of Contents

ENBRIDGE ENERGY PARTNERS, L.P.

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 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 accounting principles generally accepted in the United States of America 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, 2011, our results of operations for the three and six month periods ended June 30, 2011 and 2010 and our cash flows for the six month periods ended June 30, 2011 and 2010. We derived our consolidated statement of financial position as of December 31, 2010 from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010. Our results of operations for the three and six month periods ended June 30, 2011 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 and the impact of forward natural gas 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 interim consolidated financial statements should be read in conjunction with our consolidated financial statements and notes thereto presented in our Annual Report on Form 10-K for the fiscal year ended December 31, 2010.

Comparative Amounts

We have made reclassifications to the amounts reported in our consolidated statement of cash flows as of June 30, 2010 to conform to our current year presentation. We reclassified $4.3 million from “Other” to “Environmental costs, net of recoveries” in our consolidated statement of cash flows. We also reclassified $4.9 million from “Accounts payable and other” to “Environmental liabilities” in our consolidated statement of cash flows for the six month period ended June 30, 2010. These reclassifications did not impact our net cash provided by operating activities for the six month period ended June 30, 2010. We made a reclassification of $0.1 million of recoveries and $4.5 million of costs from “Operating and administrative” to “Environmental costs, net of recoveries” in our consolidated statements of income for the three and six month periods ended June 30, 2010, respectively. Additionally, in our consolidated statement of income, we made a reclassification of $1.1 million for oil measurement losses from “Operating and administrative” to “Oil measurement adjustments” for the three month period ended June 30, 2010.

2. NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST

In February 2011, the board of directors of Enbridge Energy Management, L.L.C., or Enbridge Management, as delegate of our General Partner, approved a split of our units to be effected by a distribution on April 21, 2011 of one common unit for each common unit outstanding and one i-unit for each i-unit outstanding to unit holders of record on April 7, 2011. As a result of this unit split, we have retrospectively restated the computation of our “Net income per limited partner unit (basic and diluted)” in the table below and restated the number of units in our consolidated statement of financial position to present the prior year amounts on a split-adjusted basis. Additionally, the formula for distributing available cash among our General Partner and limited partners was revised to reflect this unit split, as set forth in our partnership agreement, as amended, and is presented below.

 

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

 

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We allocate our net income among our General Partner and limited partners using the two-class method in accordance with applicable authoritative accounting guidance. Under the two-class method, we allocate our net income, including any incentive distribution rights, or IDRs, embedded in the general partner interest, 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 percent and 98 percent, respectively, as set forth in our partnership agreement.

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,
 
     2011     2010     2011     2010  
     (in millions, except per unit amounts)  

Net income

   $ 171.0      $ 154.5      $ 302.8      $ 280.6   

Less: Net income attributable to noncontrolling interest

     14.1        14.5        28.8        25.2   
                                

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

     156.9        140.0        274.0        255.4   

Less distributions paid:

        

Incentive distributions to our General Partner

     (24.0     (17.2     (42.4     (31.4

Distributed earnings allocated to our General Partner

     (2.8     (2.5     (5.5     (4.9
                                

Total distributed earnings to our General Partner

     (26.8     (19.7     (47.9     (36.3

Total distributed earnings to our limited partners

     (140.4     (122.0     (271.3     (240.3
                                

Total distributed earnings

     (167.2     (141.7     (319.2     (276.6
                                

Overdistributed earnings

   $ (10.3   $ (1.7   $ (45.2   $ (21.2
                                

Weighted average limited partner units outstanding

     255.2        236.5        254.0        236.2   
                                

Basic and diluted earnings per unit:

        

Distributed earnings per limited partner unit(1)

   $ 0.55      $ 0.52      $ 1.07      $ 1.02   

Overdistributed earnings per limited partner unit(2)

     (0.04     (0.01 )       (0.17 )       (0.09
                                

Net income per limited partner unit (basic and diluted)

   $ 0.51      $ 0.51      $ 0.90      $ 0.93   
                                

 

(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 percent) of distributions in excess of earnings divided by the weighted average number of limited partner interests outstanding for the period and under distributed earnings allocated to the limited partners based on the distribution waterfall that is outlined in our partnership agreement.

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 $24.4 million at June 30, 2011 and $28.9 million at December 31, 2010 are included in “Accounts payable and other” on our consolidated statements of financial position.

 

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Table of Contents

4. INVENTORY

Our inventory is comprised of the following:

 

     June 30,
2011
     December 31,
2010
 
     (in millions)  

Materials and supplies

   $ 2.2       $ 6.3   

Crude oil inventory

     9.7         8.1   

Natural gas and NGL inventory

     126.1         120.3   
                 
   $ 138.0       $ 134.7   
                 

The “Cost of natural gas” on our consolidated statements of income for the three and six month periods ended June 30, 2011 includes charges totaling $0.2 million 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. Similar charges of $1.5 million and $2.6 million were recorded to reduce our natural gas and NGLs inventories for the three and six month periods ended June 30, 2010.

5. PROPERTY, PLANT AND EQUIPMENT

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

 

     June 30,
2011
    December 31,
2010
 
     (in millions)  

Land

   $ 35.8      $ 35.7   

Rights-of-way

     519.0        510.9   

Pipelines

     6,067.3        5,981.6   

Pumping equipment, buildings and tanks

     1,360.7        1,306.9   

Compressors, meters and other operating equipment

     1,489.2        1,477.8   

Vehicles, office furniture and equipment

     202.1        201.6   

Processing and treating plants

     438.7        438.3   

Construction in progress

     631.6        401.9   
                

Total property, plant and equipment

     10,744.4        10,354.7   

Accumulated depreciation

     (1,884.6     (1,713.1
                

Property, plant and equipment, net

   $ 8,859.8      $ 8,641.6   
                

6. DEBT

Credit Facilities

Our credit facilities consist of our $1,167.5 million Second Amended and Restated Credit Agreement, or Credit Facility, and our $350 million unsecured senior revolving credit agreement. The two credit agreements, which we collectively refer to as the Credit Facilities, provide an aggregate amount of $1,517.5 million of bank credit which also supports our commercial paper program.

On July 20, 2011, we amended the $350 million unsecured senior revolving credit agreement to reflect an increase in the lending commitments to $600 million. The amended $600 million credit agreement has terms consistent with our existing Credit Facility and has the same maturity date of April 4, 2013. After this amendment, our Credit Facilities provide an aggregate amount of $1,767.5 million of bank credit.

Effective March 31, 2011, our Credit Facilities were amended to further modify the definition of Consolidated EBITDA, as set forth in the terms of our Credit Facilities, to increase from $450 million to $550 million, the aggregate amount of the costs associated with the crude oil releases on Lines 6A and 6B that are excluded from the computation of Consolidated EBITDA. Specifically, the costs allowed to be excluded from

 

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Consolidated EBITDA are those for emergency response, environmental remediation, cleanup activities, costs to repair the pipelines, inspection costs, potential claims by third parties and lost revenue. At June 30, 2011 we were in compliance with the terms of our financial covenants.

The amounts we may borrow under the terms of our Credit Facilities are reduced by the principal amount of our commercial paper issuances, if any, and the balance of our letters of credit outstanding. At June 30, 2011, we could borrow $391.8 million under the terms of our Credit Facilities, determined as follows:

 

     (in millions)  

Total credit available under Credit Facilities

   $ 1,517.5   

Less: Amounts outstanding under Credit Facilities

     75.0   

  Principal amount of commercial paper issuances

     1,000.0   

  Balance of letters of credit outstanding

     50.7   
        

Total amount we could borrow at June 30, 2011

   $ 391.8   
        

Individual borrowings under the terms of our Credit Facilities generally become due and payable at the end of each contract period, which is typically a period of three months or less. We have the option to repay these amounts on a non-cash basis by net settling with the parties to our Credit Facilities, which we accomplish by contemporaneously borrowing at the then current rate of interest and repaying the principal amount due. We net settled borrowings of $915.0 million for the six month period ended June 30, 2010, on a non-cash basis.

Commercial Paper

We have a commercial paper program that provides for the issuance of up to $1 billion in aggregate principal amount of commercial paper that 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, 2011, we had $1 billion of commercial paper outstanding at a weighted average interest rate of 0.35%, excluding the effect of our interest rate hedging activities. At December 31, 2010, we had $885.0 million of commercial paper outstanding at a weighted average interest rate of 0.44%, excluding the effect of our interest rate hedging activities. The commercial paper we can issue is limited by the credit available under our Credit Facilities.

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

Senior Notes due 2019

The holders of our Senior Notes due 2019 have an option to require us to repurchase all or a portion of the notes on March 1, 2012 at a purchase price of 100 percent of the principal amount of the notes tendered plus accrued and unpaid interest. If the holders of the senior notes require us to repay the notes on March 1, 2012, we have the ability and intent to finance them on a long-term basis through borrowings under our unsecured, long-term Credit Facilities, including the $250 million of additional capacity resulting from the July 2011 amendment to our unsecured senior revolving credit agreement. Accordingly, such amounts have been classified as “Long-term debt” in our accompanying consolidated statements of financial position.

 

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Fair Value of Debt Obligations

The table below presents the carrying amounts and approximate fair values of our debt obligations. The carrying amounts of our outstanding commercial paper and borrowings on our Credit Facilities approximate their fair values at June 30, 2011 and December 31, 2010 due to the short-term nature and frequent repricing of these obligations. The fair value of our outstanding commercial paper, borrowings on our Credit Facilities and our Senior Notes due 2019 are included with our long-term debt obligations below since we have the ability to refinance the amounts 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.

 

     June 30, 2011      December 31, 2010  
     Carrying
Amount
     Fair
Value
     Carrying
Amount
     Fair
Value
 
     (in millions)  

Commercial Paper

   $ 1,000.0       $ 1,000.0       $ 884.9       $ 884.9   

Credit Facility

     75.0         75.0                   

9.150% First Mortgage Notes

     31.0         32.2         31.0         33.5   

7.900% Senior Notes due 2012

     100.0         109.6         100.0         112.1   

4.750% Senior Notes due 2013

     199.9         212.2         199.9         214.4   

5.350% Senior Notes due 2014

     200.0         220.7         200.0         221.8   

5.875% Senior Notes due 2016

     299.8         339.0         299.8         338.1   

7.000% Senior Notes due 2018

     99.9         118.9         99.9         119.2   

6.500% Senior Notes due 2018

     398.6         463.4         398.5         463.0   

9.875% Senior Notes due 2019

     500.0         693.0         499.9         699.1   

5.200% Senior Notes due 2020

     499.8         529.3         499.8         526.6   

7.125% Senior Notes due 2028

     99.8         120.6         99.8         121.7   

5.950% Senior Notes due 2033

     199.7         206.3         199.7         209.0   

6.300% Senior Notes due 2034

     99.8         106.6         99.8         108.2   

7.500% Senior Notes due 2038

     399.0         484.1         398.9         493.0   

5.500% Senior Notes due 2040

     398.5         363.7         398.5         371.6   

8.050% Junior subordinated notes due 2067

     399.5         447.4         399.5         408.5   
                                   

Total

   $ 5,000.3       $ 5,522.0       $ 4,809.9       $ 5,324.7   
                                   

7. PARTNERS’ CAPITAL

Split of Partnership Units

Effective April 21, 2011, the board of directors of Enbridge Management, as delegate of our General Partner, approved a two-for-one split of our common units and i-units outstanding to unit holders of record on April 7, 2011. The net income per share and weighted average shares outstanding for the three and six month periods ended June 30, 2010 presented in our consolidated statements of income and the number of units presented in our consolidated statements of financial position are presented reflecting the retroactive effects of the share split.

 

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Distribution to Partners

The following table sets forth our distributions, as approved by the board of directors of Enbridge Management, during the six month period ended June 30, 2011.

 

Distribution

Declaration Date

  Record Date   Distribution
Payment Date
  Distribution
per Unit(1)
    Cash
available
for
distribution
    Amount of
Distribution
of i-units to
i-unit
Holders(2)
    Retained
from
General
Partner(3)
    Distribution
of Cash
 
(in millions, except per unit amounts)  

January 28, 2011

  February 4, 2011   February 14, 2011   $ 0.51375      $ 150.5      $ 18.1      $ 0.4      $ 132.0   

April 28, 2011

  May 6, 2011   May 13, 2011   $ 0.51375      $ 152.0      $ 18.4      $ 0.4      $ 133.2   

 

(1) 

Distributions per unit for the distribution paid on February 14, 2011 are presented retrospectively applying the two-for-one split of our units.

 

(2) 

We issued 1,124,934 split adjusted i-units, to Enbridge Management, the sole owner of our i-units, during 2011 in lieu of cash distributions.

 

(3) 

We retained an amount equal to two percent of the i-unit distribution from our General Partner to maintain its two percent 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, Enbridge Energy, Limited Partnership, or the OLP, for the three and six month periods ended June 30, 2011 and 2010. The noncontrolling interest in the OLP arises from the joint funding arrangement with our General Partner and its affiliate to finance 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.

 

     For the three month periods
ended June 30,
    For the six month periods
ended June 30,
 
           2011                 2010                 2011                 2010        
     (in millions)  

General and limited partner interests

        

Beginning balance

   $ 3,585.6      $ 3,805.5      $ 3,541.8      $ 3,803.4   

Proceeds from issuance of partnership interests, net of costs

     17.3        15.1        76.0        15.1   

Capital contribution

                          1.9   

Net income

     156.9        140.0        274.0        255.4   

Distributions

     (133.2     (117.8     (265.2     (233.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ 3,626.6      $ 3,842.8      $ 3,626.6      $ 3,842.8   
  

 

 

   

 

 

   

 

 

   

 

 

 

Accumulated other comprehensive income (loss)

        

Beginning balance

   $ (179.1   $ (68.1   $ (121.7   $ (74.6

Net realized losses on changes in fair value of derivative financial instruments reclassified to earnings

     27.3        9.0        46.1        18.9   

Unrealized net loss on derivative financial instruments

     (31.0     (61.9     (107.2     (65.3
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ (182.8   $ (121.0   $ (182.8   $ (121.0
  

 

 

   

 

 

   

 

 

   

 

 

 

Noncontrolling interest

        

Beginning balance

   $ 461.5      $ 429.1      $ 465.4      $ 341.1   

Capital contributions

     0.1        9.7        3.3        87.0   

Comprehensive income:

        

Net income

     14.1        14.5        28.8        25.2   

Distributions to noncontrolling interest

     (21.6            (43.4       
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ 454.1      $ 453.3      $ 454.1      $ 453.3   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total partners’ capital at end of period

   $ 3,897.9      $ 4,175.1      $ 3,897.9      $ 4,175.1   
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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Equity Distribution Agreement

In June 2010, we entered into an Equity Distribution Agreement, or EDA, for the issue and sale from time to time of our Class A common units up to an aggregate amount of $150.0 million. The EDA allowed us to issue and sell our Class A common units at prices we deemed appropriate for our Class A common units. Under the EDA, we sold 2,118,025 Class A common units, representing 4,236,050 units after giving effect to a two-for-one split of our Class A common units that became effective on April 21, 2011, for aggregate gross proceeds of $124.8 million, of which $64.5 million are gross proceeds received in 2011. No further sales will be made under that agreement. On May 27, 2011, we de-registered the remaining aggregate $25.2 million of Class A common units that were registered for sale under the EDA and remained unsold as of that date.

On May 27, 2011, the Partnership entered into an Amended and Restated Equity Distribution Agreement, or Amended EDA, for the issue 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. The units issued under the Amended EDA are in addition to the units offered and sold under the EDA. The issue and sale of our Class A common units, pursuant to the Amended EDA, may be conducted on any day that is a trading day for the New York Stock Exchange, unless we have suspended sales under that agreement.

The following table presents the net proceeds from our Class A common unit issuances, pursuant to the Amended EDA, during the three month period ended June 30, 2011:

 

Issuance Date

   Number of
Class A
common units
Issued
     Average
Offering
Price per
Class A
common unit
     Net Proceeds to
the Partnership(1)
     General
Partner
Contribution(2)
     Net Proceeds
Including
General Partner
Contribution
 
     (unaudited; in millions, except units and per unit amounts)  

May 27 to June 30, 2011

     333,794       $ 30.30       $ 9.9       $ 0.2       $ 10.1   

 

(1) 

Net of commissions and issuance costs of $0.2 million for the three month period ended June 30, 2011.

 

(2) 

Contributions made by the General Partner to maintain its two percent general partner interest.

8. RELATED PARTY TRANSACTIONS

Joint Funding Arrangement for Alberta Clipper Pipeline

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 Inc., or 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, 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, at which time we also terminated the A1 Credit Agreement. The promissory note payable, which we refer to as 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 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. 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).

 

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A summary of the cash activity for the A1 Term Note for the six month periods ended June 30, 2011 and 2010 are as follows:

 

     A1 Term Note  
   2011     2010  
     (in millions)  

Beginning Balance

   $ 347.4      $   

Repayments

     (6.4       

Borrowings

     7.0        340.9   
                

Ending Balance

   $ 348.0      $ 340.9   
                

Our General Partner also made equity contributions totaling $3.3 million and $87.0 million to the OLP during the six month periods ended June 30, 2011 and 2010, respectively, to fund its equity portion of the construction costs associated with the Alberta Clipper Pipeline.

We allocated earnings derived from operating the Alberta Clipper Pipeline in the amounts of $14.1 million and $28.8 million to our General Partner for its 66.67 percent share of the earnings of the Alberta Clipper Pipeline for the three and six month periods ended June 30, 2011, respectively. We allocated $14.5 million and $25.2 million for the same three and six month periods ended June 30, 2010, 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, 2011, 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 interst
     Total Series AC
Distribution
 
(in millions)  

January 28, 2011

   February 14, 2011    $ 10.9       $ 21.8       $ 32.7   

April 28, 2011

   May 13, 2011      10.8         21.6         32.4   
                             
      $ 21.7       $ 43.4       $ 65.1   
                             

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 could, at times, be 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, 2011 and December 31, 2010, we have $49.9 million and $44.2 million, respectively, included in “Other long-term liabilities,” that we have accrued for costs we have incurred primarily to address remediation of contaminated sites, asbestos containing materials, management of hazardous waste material disposal, outstanding air quality measures for certain of our liquids and natural gas assets, and penalties we have been or expect to be assessed.

Lakehead Lines 6A & 6B Crude Oil Releases

Line 6B Crude Oil Release

We continue to make visible progress on the cleanup, remediation and restoration of the areas affected by the Line 6B crude oil release. A significant portion of the effort to cleanup, remediate and restore the areas affected by the Line 6B crude oil release was performed by the end of 2010. However, we continue to remediate identified sites, and we expect to make payments for additional costs associated with remediation and restoration of the area, air and groundwater monitoring, along with other legal, professional and regulatory costs through future periods. All the initiatives we will undertake in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

We have revised our total estimate for this crude oil release to $585 million, as of June 30, 2011, an increase of $35.0 million from March 31, 2011, based on additional information concerning the reassessment of the overall monitoring area, related cleanup, including submerged oil recovery operations, and remediation activities. This estimate is before insurance recoveries and excluding fines and penalties. For purposes of estimating our expected losses associated with the Line 6B crude oil release, we have included those costs that we considered probable and that could be reasonably estimated at June 30, 2011. Our estimates do not include amounts we have capitalized or any fines, penalties and claims associated with the release that may later become evident. 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 invoices are received for the actual personnel, equipment and services, our estimates will continue to be further refined. Our estimates also consider currently available facts, existing technology and presently enacted laws and regulations. These amounts also consider our and other companies’ prior experience remediating contaminated sites and data released by government organizations. Despite the efforts we have made to ensure the reasonableness of our estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. We 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

   $ 197   

Environmental Consultants

     113   

Professional, regulatory and other

     275   
        

Total

   $ 585   
        

We expect that we will have paid approximately 80 to 90 percent of the estimated costs associated with this crude oil release by the end of 2011. We have made payments totaling $422.3 million for costs associated with the Line 6B crude oil release, $128.7 million of which relates to the six month period ended June 30, 2011. We have a remaining liability of $162.7 million, a majority of which is presented as current, on our consolidated statement of financial position at June 30, 2011. Additionally, we recognized $15.0 million and $50.0 million of insurance recoveries in our consolidated statements of income for the three and six month periods ended June 30, 2011.

 

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Line 6A Crude Oil Release

We are continuing to monitor the areas affected by the crude oil release from Line 6A of our Lakehead system for any additional requirements. We have substantially completed the cleanup, remediation and restoration of the areas affected by the release.

In connection with this crude oil release, we have revised our original estimate to $48 million, an increase of $3.0 million from March 31, 2011, based on a refinement of our future costs based on additional information. This estimate is before insurance recoveries and excluding fines and penalties. We continue to monitor this estimate based upon actual invoices received and paid for the personnel, equipment and services provided by our vendors and currently available facts specific to these circumstances, existing technology and presently enacted laws and regulations to determine if our estimate should be updated. We have made payments totaling $43.7 million for costs associated with the Line 6A crude oil release, $9.3 million of which relates to the six month period ended June 30, 2011. We have a remaining total liability of $4.3 million, a majority of which is presented as current, on our consolidated statement of financial position as of June 30, 2011.

We have the potential of incurring additional costs in connection with this crude oil release, including fines and penalties as well as expenditures associated with litigation.

Lines 6A & 6B Fines and Penalties

Our estimated environmental costs for both the Line 6A and Line 6B crude oil releases do not include an estimate for fines and penalties at June 30, 2011, which may be imposed by the Environmental Protection Agency, or EPA, and Pipeline and Hazardous Materials Safety Administration, or PHMSA, in addition to other state and local governmental agencies. Several factors remain outstanding at the end of the period that we consider critical in estimating the amount of fines and penalties that we may be assessed.

Due to the absence of sufficient information, we cannot provide a reasonable estimate of our liability for fines and penalties that we could be assessed in connection with each of the releases. As a result, we have not recorded any liability for expected fines and penalties.

Insurance Recoveries

We are included in the comprehensive insurance program that is maintained by Enbridge for its subsidiaries and affiliates, which renews May of each year. The program 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. The claims for the crude oil releases from Lines 6A and 6B are covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650 million for pollution liability. Assuming that all of the claims for the releases are recoverable under this insurance policy, the occurrence-based coverage remaining under the commercial liability insurance policies related to costs associated with Lines 6A and 6B, and other claims of Enbridge and its subsidiaries and affiliates, including us, is approximately $20 million based on estimates as of June 30, 2011.

We anticipate that substantially all of the costs we have incurred from the crude oil releases will ultimately be recoverable under our existing insurance policies, except for fines and penalties and other amounts for which we are not insured. We recognized $15.0 million and $50.0 million of insurance recoveries as reductions to “Environmental costs, net of recoveries” in our consolidated statements of income for the three and six month periods ended June 30, 2011, respectively. At June 30, 2011, we have $15.0 million recorded in “Receivables, trade and other” in our consolidated statement of financial position for an insurance payment received in July 2011 for a claim we filed in connection with the Line 6B crude oil release. In second quarter 2011, we received insurance payments of $35 million for claims we filed. We expect to record a receivable 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.

During the second quarter of 2011, Enbridge renewed its comprehensive insurance program and the current coverage year has an aggregate limit of $575.0 million for pollution liability for the period May 1, 2011 through April 30, 2012.

 

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Pipeline Integrity Commitment

In connection with the restart of Line 6B of our Lakehead system, we committed to accelerate a process we had initiated prior to the crude oil release to perform additional inspections, testing and refurbishment of Line 6B within and beyond the immediate area of the July 26, 2010 crude oil release. Pursuant to this agreement with PHMSA, we completed remediation of those pipeline anomalies identified by us between the years 2007 and 2009 that were scheduled for refurbishment and anomalies identified for action in a July 2010 PHMSA notification on schedule, within 180 days of the September 27, 2010 restart of Line 6B, as required. In addition to the required integrity measures, we also agreed to replace a 3,600 foot section of the Line 6B pipeline that lies underneath the St. Clair River in Michigan within one year of the restart of Line 6B, subject to obtaining required permits. A new line was installed beneath the St. Clair River in March 2011 and was tied into Line 6B during June 2011.

On May 12, 2011 we announced plans to replace 75-miles of non-contiguous sections of Line 6B of our Lakehead system at an estimated cost of $286 million. Our Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. Subject to regulatory approvals, the new segments of pipeline will be constructed mostly in 2012 and are targeted to be placed in-service by the first quarter of 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries.

In February 2011, we filed a supplement to our Facilities Surcharge Mechanism, or FSM, to be effective on April 1, 2011, for recovery of $175 million of capital costs and $5 million of operating costs for the 2010 and 2011 Line 6B Integrity Program. The costs associated with the Line 6B Integrity Program, which include an equity return component, interest expense and an allowance for income taxes, will be recovered over a 30-year period, while operating costs will be recovered through our annual tolls for actual costs incurred. These costs include costs associated with the PHMSA Corrective Action Order and other required integrity work.

The total cost of these integrity measures is separate from the environmental liabilities discussed above. The pipeline integrity and replacement costs will be capitalized or expensed in accordance with our capitalization policies as these costs are incurred, the majority of which are expected to be capital in nature.

Gain Contingencies

We received proceeds of $11.6 million for settlement of claims we made for payment from unrelated parties in connection with operational matters that occurred in the normal course of business. We recorded $5.6 million as a reduction to “Operating and administrative” expenses of our Liquids segment and $6.0 million as “Other income” in our consolidated statements of income for the six month period ended June 30, 2011 for the amounts we received in April 2011.

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 6A and Line 6B crude oil releases. Approximately twenty-five actions or claims have been filed against us and our affiliates, in state and federal courts in connection with the Line 6B crude oil release, including direct actions, actions seeking class status. With respect to the Line 6B crude oil release, no penalties or fines have been assessed against us as of June 30, 2011. Governmental agencies and regulators have also initiated investigations into the Line 6A crude oil release. One claim has been filed against us and our affiliates, by the State of Illinois, in state court in connection with this crude oil release. The parties are operating under an agreed interim order which we expect to mature into a final order in the near future, thereby resolving that proceeding. The costs associated with this order are included in the estimated environmental costs accrued for Line 6A. We have provided a retention fund for future legal costs associated with the Line 6A and Line 6B crude oil releases as described above in the section titled Lakehead Lines 6A & 6B Crude Oil Releases of this footnote.

 

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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 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 to our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating 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 2016 in accordance with our risk management policies.

We record all derivative financial instruments in our consolidated financial statements at fair market value, which we adjust each period for changes in the fair market value, and refer to as marking to market, or mark-to-market. The fair market value of these derivative financial instruments reflects the estimated amounts that we would pay to transfer a liability or receive to sell an asset in an orderly transaction with market participants to terminate or close the contracts at the reporting date, taking into account the current unrealized losses or gains on open contracts. We apply the market approach to value substantially all of our derivative instruments. Actively traded external market quotes, data from pricing services and published indices are used to value our 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.

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 and interest rate 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” 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 Marketing 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.

 

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Storage—In our Marketing segment, we use derivative financial instruments (i.e., natural gas swaps) to hedge the relative difference between the injection price paid to purchase and store natural gas and the withdrawal price at which the natural gas is 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 injected and the price received upon withdrawal of the natural gas from storage in a future period. We do not pursue cash flow hedge accounting treatment for these storage transactions since the underlying forecasted injection or withdrawal of natural gas 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 natural gas is 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 natural gas is sold from storage. As a result, derivative financial instruments associated with our natural gas storage activities can create volatility in our earnings.

 

   

Natural Gas Collars—In our Natural Gas segment, we previously entered into natural gas collars to hedge the sales price of natural gas. The natural gas collars were based on a New York Mercantile Exchange, or NYMEX, pricing index, while the physical gas sales were based on a different index. To better align the index of the natural gas collars with the index of the underlying sales, we de-designated the original cash flow hedging relationship with the intent of contemporaneously re-designating the natural gas collars as hedges of forecasted physical natural gas sales with a NYMEX pricing index. However, because the fair value of these derivative instruments was a liability to us at re-designation, they are considered net written options and, pursuant to the authoritative accounting guidance, do not qualify for hedge accounting. These derivatives are being marked-to-market, with the changes in fair value from the date of de-designation recorded to earnings each period. As a result, our operating income is subject to greater volatility due to movements in the prices of 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 Forward Contracts—In our Natural Gas segment, we use forward contracts to fix the price of NGLs we purchase and store in inventory and to fix the price of NGLs that we sell from inventory to meet the demands of our customers that sell and purchase NGLs. Prior to April 1, 2009, these forward contracts were not treated as derivative financial instruments pursuant to the normal purchase normal sale, or NPNS, exception allowed under authoritative accounting guidance, since the forward contracts resulted in physical receipt or delivery of NGLs. However, evolving markets for NGLs have increased opportunities for a portion of our forward contracts to be settled net rather than physically receiving or delivering the NGLs. Accordingly, we have revoked the NPNS election on certain forward contracts associated with the liquids marketing operations of Dufour Petroleum, L.P., our wholly-owned subsidiary, executed after April 1, 2009. The forward contracts for which we have revoked the NPNS election do not qualify for hedge accounting and are being marked-to-market each period with the changes in fair value recorded in earnings. As a result, our operating income is subject to additional volatility associated with fluctuations in NGL prices until the forward contracts are settled.

 

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Natural Gas Forward Contracts—In our Marketing segment, we use forward contracts to sell natural gas to our customers. Historically, we have not considered these contracts to be derivatives under the NPNS exception allowed by authoritative accounting guidance. In the first quarter of 2010, we determined that a sub-group of physical natural gas sales contracts with terms allowing for economic net settlement did not qualify for the NPNS scope exception, and are being marked-to-market each period with the changes 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 our pipelines operate have legislated either partially or fully deregulated power markets, we have the opportunity to create economic hedges on power exposure within the requirements of applicable risk policies. 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 market 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 historical cost) 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.

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:

 

   

Natural Gas and Marketing segments commodity-based derivatives—“Cost of natural gas”

 

   

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

 

   

Corporate interest rate derivatives—“Interest expense”

 

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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 unrealized gains and losses associated with the changes in fair value of our derivative financial instruments:

 

     For the three month
period ended

June 30,
    For the six month
period ended

June 30,
 
         2011             2010             2011             2010      
     (in millions)  

Liquids segment

        

Non-qualified hedges

   $ 9.4      $ 1.6      $ 4.8      $ 0.4   

Natural Gas segment

        

Hedge ineffectiveness

     0.1        0.9        1.3        1.4   

Non-qualified hedges

     9.5        19.2        (0.8     28.9   

Marketing

        

Non-qualified hedges

     1.2        (3.9     (1.7     (4.3
                                

Commodity derivative fair value net gains

     20.2        17.8        3.6        26.4   

Corporate

        

Non-qualified interest rate hedges

     (0.2            (0.3     (0.5
                                

Derivative fair value net gains

   $ 20.0      $ 17.8      $ 3.3      $ 25.9   
                                

Derivative Positions

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

 

     June  30,
2011
    December  31,
2010
 
    
     (in millions)  

Other current assets

   $ 26.9      $ 37.1   

Other assets, net

     3.8        5.0   

Accounts payable and other

     (89.6     (79.2

Other long-term liabilities

     (104.4     (67.1
                
   $ (163.3   $ (104.2
                

The changes in the net 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 long-term natural gas, NGL and crude oil sales and purchase contracts.

We record the change in fair value of our highly effective cash flow hedges in “Accumulated other comprehensive income,” or AOCI, until the derivative financial instruments are settled, at which time they are reclassified to earnings. Also included in AOCI are unrecognized losses of approximately $32.4 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 three month period ended June 30, 2011, $5.1 million of unrealized commodity hedge losses were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $55.5 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at June 30, 2011, will be reclassified from AOCI to earnings during the next 12 months.

 

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

 

     June 30,
2011
    December 31,
2010
 
     (in millions)  

Counterparty Credit Quality*

  

AAA

   $ (0.1   $   

AA

     (85.9     (48.7

A

     (81.3     (61.3

Lower than A

     4.0        5.8   
                
   $ (163.3   $ (104.2
                

 

* As determined by nationally-recognized statistical ratings organizations.

As the net value of our derivative financial instruments has decreased in response to changes in forward commodity prices, our outstanding financial exposure to third parties has also declined. When credit thresholds are met pursuant to the terms of our International Securities Dealers Association, or ISDA®, financial contracts, we have the right to require collateral from our counterparties. We have included any cash collateral received in the balances listed above. 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.

The ISDA® agreements and associated credit support, which govern our financial derivative transactions, contain no credit rating downgrade triggers that would accelerate the maturity dates of our outstanding transactions. A change in ratings is not an event of default under these instruments, and the maintenance of a specific minimum credit rating is not a condition to transacting under the ISDA® agreements. In the event of a credit downgrade, additional collateral may be required to be posted under the agreement if we are in a liability position to our counterparty, but the agreement will not automatically terminate or require immediate settlement of all future amounts due.

The ISDA® agreements, in combination with our master netting agreements, and credit arrangements governing our interest rate and commodity swaps require that collateral be posted per tiered contractual thresholds based on the credit rating of each counterparty. We generally provide letters of credit to satisfy such collateral requirements under our ISDA® agreements. These agreements will require additional collateral postings of up to 100% on net liability positions in the event of a credit downgrade below investment grade. Automatic termination clauses which exist are related only to non-performance activities, such as the refusal to post collateral when contractually required to do so. When we are holding an asset position, our counterparties are likewise required to post collateral on their liability (our asset) exposures, also determined by the tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

At June 30, 2011, we were in an overall net liability position of $163.3 million, which included assets of $30.7 million. 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, 2011 we would have been required to provide additional letters of credit in the amount of $77.5 million.

 

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At June 30, 2011 and December 31, 2010, we had credit concentrations in the following industry sectors, as presented below:

 

     June 30,
2011
    December 31,
2010
 
     (in millions)  

United States financial institutions and investment banking entities

   $ (96.4   $ (53.2

Non-United States financial institutions

     (57.5     (46.8

Other

     (9.4     (4.2
                
   $ (163.3   $ (104.2
                

We are holding no cash collateral on our asset exposures, and we have provided letters of credit totaling $50.1 million and $7.3 million relating to our liability exposures pursuant to the margin thresholds in effect at June 30, 2011 and December 31, 2010, respectively, under our ISDA® agreements.

Gross derivative balances are presented below without the effects of collateral received or posted and without the effects of master netting arrangements. Our assets are adjusted for the non-performance risk of our counterparties using their credit default swap spread rates and are reflected in the fair value. Likewise, in the case of our liabilities, our nonperformance risk is considered in the valuation and is also adjusted based on current credit default swap spread rates on our outstanding indebtedness. Our credit exposure for these over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. A reconciliation between the derivative balances presented at gross values rather than the net amounts we present in our other derivative disclosures, is also provided below.

Effect of Derivative Instruments on the Consolidated Statements of Financial Position

 

   

Asset Derivatives

   

Liability Derivatives

 
        Fair Value at         Fair Value at  
   

Financial Position
Location

  June 30,
2011
    December 31,
2010
   

Financial Position Location

  June 30,
2011
    December 31,
2010
 
    (in millions)  

Derivatives designated as hedging instruments

           

Interest rate contracts

  Other current assets   $ 14.4      $ 22.9      Accounts payable and other   $ (21.7   $ (21.4

Interest rate contracts

  Other assets, net     0.2        2.5      Other long-term liabilities     (59.8     (44.0

Commodity contracts

  Other current assets     3.5        10.7      Accounts payable and other     (43.1     (43.4

Commodity contracts

  Other assets, net     10.0        14.1      Other long-term liabilities     (56.4     (38.1
                                   
      28.1        50.2          (181.0     (146.9
                                   

Derivatives not designated as hedging instruments

           

Interest rate contracts

  Other current assets     5.2        5.1      Accounts payable and other     (4.7     (4.6

Interest rate contracts

  Other assets, net     4.9        6.6      Other long-term liabilities     (4.4     (5.9

Commodity contracts

  Other current assets     26.0        23.7      Accounts payable and other     (42.3     (35.1

Commodity contracts

  Other assets, net     8.1        8.7      Other long-term liabilities     (3.2     (6.0
                                   
      44.2        44.1          (54.6     (51.6
                                   

Total derivative instruments

    $ 72.3      $ 94.3        $ (235.6   $ (198.5
                                   

 

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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, 2011

     

Interest rate contracts

  $ (43.2   Interest expense   $ (6.5   Interest expense   $   

Commodity contracts

    44.5      Cost of natural gas     (20.8   Cost of natural gas     0.1   
                           

Total

  $ 1.3        $ (27.3     $ 0.1   
                           

For the three month period ended June 30, 2010

     

Interest rate contracts

  $ (86.2   Interest expense   $ (2.0   Interest expense   $   

Commodity contracts

    33.6      Cost of natural gas     (7.0   Cost of natural gas     0.9   
                           

Total

  $ (52.6     $ (9.0     $ 0.9   
                           

For the six month period ended June 30, 2011

     

Interest rate contracts

  $ (26.9   Interest expense   $ (13.4   Interest expense   $   

Commodity contracts

    (29.3   Cost of natural gas     (32.7   Cost of natural gas     1.3   
                           

Total

  $ (56.2     $ (46.1     $ 1.3   
                           

For the six month period ended June 30, 2010

     

Interest rate contracts

  $ (100.1   Interest expense   $ (3.4   Interest expense   $   

Commodity contracts

    67.2      Cost of natural gas     (15.5   Cost of natural gas     1.4   
                           

Total

  $ (32.9     $ (18.9     $ 1.4   
                           

 

(1) 

Includes only the ineffective portion of derivatives that are designated as hedging instruments and does not include net gains or losses associated with derivatives that do not qualify for hedge accounting treatment.

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,
 
          2011     2010      2011     2010  

Derivatives Not Designated as Hedging
Instruments

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

Interest rate contracts

  Interest expense    $ (0.2   $       $ (0.3   $ (0.5

Commodity contracts

  Operating revenue      9.7        1.6         5.2        0.4   

Commodity contracts

  Power      (0.3             (0.4       

Commodity contracts

  Cost of natural gas      10.7        15.3         (2.5     24.6   
                                   

Total

     $ 19.9      $ 16.9       $ 2.0      $ 24.5   
                                   

 

(1) 

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.

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

 

     June 30, 2011     December 31, 2010  
     Assets     Liabilities     Total     Assets     Liabilities     Total  
     (in millions)  

Fair value of derivatives—gross presentation

   $ 72.3      $ (235.6   $ (163.3   $ 94.3      $ (198.5   $ (104.2

Effects of netting agreements

     (41.6     41.6               (52.2     52.2          
                                                

Fair value of derivatives—net presentation

   $ 30.7      $ (194.0   $ (163.3   $ 42.1      $ (146.3   $ (104.2
                                                

 

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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, 2011 and December 31, 2010. 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, 2011     December 31, 2010  
     Level 1      Level 2     Level 3     Total     Level 1      Level 2     Level 3     Total  
     (in millions)  

Interest rate contracts

   $       $ (65.9   $      $ (65.9   $       $ (38.8   $      $ (38.8

Commodity contracts—financial

             (50.8     (56.0     (106.8             (52.4     (24.8     (77.2

Commodity contracts—physical

                    5.9        5.9                       3.4        3.4   

Commodity options

             (0.1     3.6        3.5                (0.2     8.6        8.4   
                                                                  

Total

   $       $ (116.8   $ (46.5   $ (163.3   $       $ (91.4   $ (12.8   $ (104.2
                                                                  

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, 2011 to June 30, 2011. No transfers of assets between any of the Levels occurred during the period.

 

     2011  
     Commodity
Financial
Contracts
    Commodity
Physical
Contracts
    Commodity
Options
    Total  

Beginning balance as of January 1

   $ (24.8   $ 3.4      $ 8.6      $ (12.8

Transfer out of Level 3(1)

                            

Gains or losses

        

Included in earnings (or changes in net assets)

     (22.6     (0.1     (0.6     (23.3

Included in other comprehensive income

     (38.0            (4.0     (42.0

Purchases, issuances, sales and settlements

        

Purchases

                            

Settlements(2)

     29.4        2.6        (0.4     31.6   
                                

Ending balance as of June 30

   $ (56.0   $ 5.9      $ 3.6      $ (46.5
                                

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

   $ (43.4   $ 4.2      $ (3.4   $ (42.6
                                

Amounts reported in operating revenue

   $ (0.2   $      $      $ (0.2
                                

 

(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, 2011 and December 31, 2010.

 

    At June 30, 2011     At December 31, 2010  
              Wtd. Average Price(2)     Fair Value(3)     Fair Value(3)  
    Commodity   Notional(1)       Receive         Pay       Asset     Liability     Asset     Liability  

Portion of contracts maturing in 2011

               

Swaps

               

Receive variable/pay fixed

  Natural Gas     5,425,773      $ 4.45      $ 4.65      $ 1.2      $ (2.3   $ 0.4      $ (4.9
  NGL     110,000      $ 88.38      $ 59.89      $ 3.1      $      $ 6.8      $   
  Crude Oil     110,000      $ 96.31      $ 102.10      $      $ (0.6   $ 0.4      $   

Receive fixed/pay variable

  Natural Gas     9,219,627      $ 4.09      $ 4.45      $ 0.9      $ (4.2   $ 2.6      $ (6.7
  NGL     2,571,176      $ 49.40      $ 63.38      $ 1.6      $ (37.5   $ 5.0      $ (38.8
  Crude Oil     940,136      $ 81.36      $ 95.67      $ 0.7      $ (14.1   $      $ (22.9

Receive variable/pay variable

  Natural Gas     48,788,861      $ 4.34      $ 4.31      $ 2.7      $ (1.3   $ 5.0      $ (1.2

Physical Contracts

               

Receive fixed/pay variable

  NGL     1,014,439      $ 80.60      $ 80.01      $ 1.4      $ (0.8   $ 0.5      $ (4.4
  Crude Oil     130,000      $ 101.01      $ 95.95      $ 0.7      $      $      $ (1.9

Receive variable/pay fixed

  NGL     223,103      $ 92.14      $ 90.33      $ 0.6      $ (0.2   $ 1.6      $   
  Crude Oil     93,000      $ 95.70      $ 98.48      $      $ (0.3   $ 1.1      $   

Pay fixed

  Power(4)     37,800      $ 34.02      $ 44.24      $      $ (0.4   $      $ (0.8

Receive variable/pay variable

  Crude Oil     543,479      $ 96.12      $ 95.67      $ 1.2      $ (0.9   $ 0.5      $ (0.2
  NGL     3,004,452      $ 76.43      $ 75.69      $ 5.2      $ (3.0   $ 6.2      $ (1.4
  Natural Gas     18,742,920      $ 4.36      $ 4.32      $ 0.7      $      $ 1.1      $   

Portion of contracts maturing in 2012

               

Swaps

               

Receive variable/pay fixed

  Natural Gas     2,362,813      $ 4.79      $ 6.40      $ 0.2      $ (4.0   $      $ (3.8

Receive fixed/pay variable

  Natural Gas     4,352,720      $ 4.82      $ 4.79      $ 1.9      $ (1.8   $ 1.7      $ (2.1
  NGL     2,067,380      $ 56.14      $ 62.48      $ 4.3      $ (17.4   $ 8.0      $ (7.6
  Crude Oil     1,418,616      $ 88.73      $ 97.83      $ 3.0      $ (15.8   $      $ (10.7

Receive variable/pay variable

  Natural Gas     51,264,000      $ 4.77      $ 4.75      $ 2.0      $ (0.9   $ 1.0      $ (0.8

Physical Contracts

               

Receive fixed/pay variable

  NGL     95,791      $ 79.19      $ 77.28      $ 0.3      $ (0.1   $      $   

Receive variable/pay variable

  Natural Gas     18,394,101      $ 4.78      $ 4.73      $ 0.8      $      $ 0.6      $   
  NGL     1,102,229      $ 70.82      $ 69.57      $ 2.4      $ (1.0   $ 0.7      $   

Pay fixed

  Power(4)     62,330      $ 35.40      $ 40.29      $      $ (0.3   $      $   

Portion of contracts maturing in 2013

               

Swaps

               

Receive variable/pay fixed

  Natural Gas     93,066      $ 5.07      $ 5.19      $      $      $      $   

Receive fixed/pay variable

  Natural Gas     730,000      $ 9.83      $ 5.01      $ 3.5      $      $ 3.3      $   
  NGL     994,260      $ 64.86      $ 74.72      $ 0.6      $ (10.3   $ 0.3      $ (3.2
  Crude Oil     1,430,435      $ 93.38      $ 100.94      $ 3.3      $ (14.0   $ 2.2      $ (7.4

Receive variable/pay variable

  Natural Gas     29,550,000      $ 5.11      $ 5.10      $ 0.4      $ (0.2   $ 0.1      $ (0.2

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     6,685,350      $ 5.14      $ 5.10      $ 0.3      $      $ 0.2      $   
  NGL     44,286      $ 65.68      $ 64.00      $ 0.1      $      $      $   

Pay fixed

  Power(4)     43,042      $ 38.41      $ 42.86      $      $ (0.2   $      $   

Portion of contracts maturing in 2014

               

Swaps

               

Receive variable/pay fixed

  Natural Gas     21,870      $ 5.42      $ 5.22      $      $      $      $   

Receive fixed/pay variable

  NGL     381,425      $ 77.58      $ 85.58      $ 0.6      $ (3.5   $      $ (1.1
  Crude Oil     1,228,955      $ 94.27      $ 100.68      $ 0.6      $ (8.2   $      $ (2.8

Receive variable/pay variable

  Natural Gas     6,300,000      $ 5.48      $ 5.49      $      $ (0.1   $      $ (0.1

Physical Contracts

               

Pay fixed

  Power(4)     58,853      $ 41.46      $ 46.58      $      $ (0.3   $      $   

Portion of contracts maturing in 2015

               

Swaps

               

Receive fixed/pay variable

  Crude Oil     865,415      $ 97.72      $ 100.31      $ 0.3      $ (2.4   $      $ (0.7
  NGL     109,500      $ 88.36      $ 91.37      $ 0.2      $ (0.5   $      $ (0.1

Portion of contracts maturing in 2016

               

Swaps

               

Receive fixed/pay variable

  Crude Oil     45,750      $ 99.31      $ 100.22      $      $      $      $   

 

(1) 

Volumes of Natural gas are measured in millions of British Thermal Units, or MMBtu, whereas volumes of NGL and crude oil are measured in barrels, or Bbl. Our power purchase agreements are measured in Megawatt hours, or MWh.

 

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(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, 2011 and December 31, 2010, 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 $0.9 million of gains and $0.6 million of gains at June 30, 2011 and December 31, 2010, respectively.

 

(4) 

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

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at June 30, 2011 and December 31, 2010.

 

     At June 30, 2011     At December 31, 2010  
     Commodity     Notional(1)      Strike
Price(2)
     Market
Price(2)
     Fair Value(3)     Fair Value(3)  
              Asset      Liability     Asset      Liability  

Portion of option contracts
maturing in 2011

                     

Calls (written)

     Natural Gas (4)      184,000       $ 4.31       $ 4.46       $       $ (0.1   $       $ (0.2

Puts (purchased)

     Natural Gas (4)      184,000       $ 3.40       $ 4.46       $       $      $       $   
     NGL       319,792       $ 54.79       $ 67.50       $ 0.7       $      $ 3.6       $   
     Crude Oil       109,480       $ 88.65       $ 96.90       $ 0.3       $      $ 1.3       $   

Portion of option contracts
maturing in 2012

                     

Puts (purchased)

     NGL        284,382       $ 65.90       $ 72.35       $ 2.6       $      $ 3.9       $   

 

(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, 2011 and December 31, 2010, 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 at December 31, 2010. No credit valuation adjustments related to our outstanding commodity options existed at June 30, 2011.

 

(4) 

Indicates transactions which, in combination, create a collar, representing a floor and ceiling on the price and provide long-term price protection.

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,
2011
    December 31,
2010
 
     (dollars in millions)              

Contracts maturing in 2013

            

Interest Rate Swaps—Pay Fixed

   Cash Flow Hedge    $ 600         4.15   $ (47.8   $ (51.8

Interest Rate Swaps—Pay Fixed

   Non-qualifying    $ 125         4.35   $ (9.3   $ (10.7

Interest Rate Swaps—Pay Float

   Non-qualifying    $ 125         4.75   $ 10.3      $ 11.9   

Contracts maturing in 2015

            

Interest Rate Swaps—Pay Fixed

   Cash Flow Hedge    $ 300         2.43   $ 0.2      $ 1.9   

Contracts settling prior to maturity

            

2011—Pre-issuance Hedges

   Cash Flow Hedge    $ 300         2.92   $ 14.5      $ 23.4   

2012—Pre-issuance Hedges

   Cash Flow Hedge    $ 600         4.57   $ (29.0   $ (13.7

2013—Pre-issuance Hedges

   Cash Flow Hedge    $ 300         4.62   $ (5.7   $ (0.3

 

(1) 

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

 

(2) 

The fair value is determined from quoted market prices at June 30, 2011 and December 31, 2010, 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 $0.9 million of gains at June 30, 2011 and $0.5 million of gains at December 31, 2010.

 

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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 that apply to entities organized as partnerships by the States of Texas and Michigan. We computed our income tax expense by applying a Texas state income tax rate to modified gross margin and a Michigan state income tax rate to modified gross receipts. The Texas state income tax rate was 0.5% for the six month periods ended June 30, 2011 and 2010. The Michigan state income tax rate was 0.2% for the six month periods ended June 30, 2011 and 2010.

On May 25, 2011, the Governor of Michigan signed legislation implementing a new corporate income tax system. The new tax system becomes effective January 1, 2012 and repeals the Michigan Business Tax, or MBT, which imposes tax on individuals, LLCs, trusts, partnerships, S corporations, and C corporations and replaces it with the Michigan Corporate Income Tax, or CIT. The CIT only taxes entities classified as C Corporations, therefore, the Partnership is excluded from the CIT and will no longer pay Michigan income taxes beginning in 2012. Due to this change as of June 30, 2011 we reversed deferred tax liabilities of $1.2 million that were previously recognized on our consolidated statements of financial position, which decreased “Income tax expense” in our consolidated statements of income for the three and six month periods ended June 30, 2011, to reflect the tax associated with the difference between the net basis in assets and liabilities for financial and state tax reporting related to Michigan income taxes.

Our income tax expense is $0.9 million and $2.4 million and $3.2 million and $4.6 million for the three and six month periods ended June 30, 2011 and 2010 respectively.

At June 30, 2011 and December 31, 2010 we have included a current income tax payable of $5.0 million and $7.9 million in “Property and other taxes payable,” respectively. In addition, at June 30, 2011 and December 31, 2010, we have included a deferred income tax liability of $2.5 million and $3.6 million, respectively, in “Other long-term liabilities,” 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. OIL MEASUREMENT ADJUSTMENTS

Oil measurement adjustments occur as part of the normal operations associated with our liquid petroleum operations. The three types of oil measurement adjustments that routinely occur on our systems include:

 

   

Physical, which result from evaporation, shrinkage, differences in measurement (including sediment and water measurement) between receipt and delivery locations and other operational conditions;

 

   

Degradation resulting from mixing at the interface within our pipeline systems or terminal and storage facilities between higher quality light crude oil and lower quality heavy crude oil in pipelines; and

 

   

Revaluation, which are a function of crude oil prices, the level of our carriers inventory and the inventory positions of customers.

Quantifying oil measurement adjustments are difficult because: (1) physical measurements of volumes are not practical, as products continuously move through our pipelines, which are primarily located underground; (2) the extensive length of our pipeline systems and (3) the numerous grades and types of crude oil products we carry. We utilize engineering-based models and operational assumptions to estimate product volumes in our systems and associated oil measurement adjustments. Material changes in our assumptions may result in revisions to our oil measurement estimates in the period determined.

We settled a dispute with a shipper on our Lakehead crude oil pipeline system, which we recognized in June 2011, for oil measurement adjustments we had previously recognized in prior years. We recorded $52.2 million to “Receivables, trade and other” on our consolidated statements of financial position at June 30, 2011 and to “Oil measurement adjustments,” which is a reduction to operating expenses, for the three and six month periods ended June 30, 2011 in our consolidated statements of income for the cash amount we received for this settlement in July 2011.

 

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13. 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 in deciding how resources are allocated and performance is assessed.

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

 

   

Liquids;

 

   

Natural Gas; and

 

   

Marketing.

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

 

    For the three month period ended June 30, 2011  
    Liquids     Natural Gas     Marketing     Corporate(1)     Total  
    (in millions)  

Total revenue

  $ 310.2      $ 1,893.9      $ 569.2      $      $ 2,773.3   

Less: Intersegment revenue

    0.3        395.8        5.2               401.3   
                                       

Operating revenue

    309.9        1,498.1        564.0               2,372.0   

Cost of natural gas

           1,299.7        561.6               1,861.3   

Environmental costs, net of recoveries

    23.3                             23.3   

Oil measurement adjustments

    (54.1                          (54.1

Operating and administrative

    73.3        91.7        1.7        0.9        167.6   

Power

    33.9                             33.9   

Depreciation and amortization

    48.8        40.8                      89.6   
                                       

Operating income

    184.7        65.9        0.7        (0.9     250.4   

Interest expense

                         78.5        78.5   
                                       

Income from continuing operations before income tax expense

    184.7        65.9        0.7        (79.4     171.9   

Income tax expense

                         0.9        0.9   
                                       

Net income

    184.7        65.9        0.7        (80.3     171.0   

Less: Net income attributable to the noncontrolling interest

                         14.1        14.1   
                                       

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

  $ 184.7      $ 65.9      $ 0.7      $ (94.4   $ 156.9   
                                       

 

(1) 

Corporate consists 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.

 

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    For the three month period ended June 30, 2010  
    Liquids     Natural Gas     Marketing     Corporate(1)     Total  
    (in millions)  

Total revenue

  $ 320.1      $ 1,246.6      $ 549.0      $      $ 2,115.7   

Less: Intersegment revenue

    0.3        358.0        10.0               368.3   
                                       

Operating revenue

    319.8        888.6        539.0               1,747.4   

Cost of natural gas

           730.8        539.6               1,270.4   

Environmental costs, net of recoveries

    (0.1                          (0.1

Oil measurement adjustments

    1.1                             1.1   

Operating and administrative

    64.2        67.9        2.0        1.2        135.3   

Power

    36.5                             36.5   

Depreciation and amortization

    46.6        31.0                      77.6   
                                       

Operating income

    171.5        58.9        (2.6     (1.2     226.6   

Interest expense

                         69.6        69.6   

Other expense

                         0.1        0.1   
                                       

Income from continuing operations before income tax expense

    171.5        58.9        (2.6     (70.9     156.9   

Income tax expense

                         2.4        2.4   
                                       

Net income

    171.5        58.9        (2.6     (73.3     154.5   

Less: Net income attributable to the noncontrolling interest

                         14.5        14.5   
                                       

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

  $ 171.5      $ 58.9      $ (2.6   $ (87.8   $ 140.0   
                                       

 

(1) 

Corporate consists 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.

 

    As of and for the six month period ended June 30, 2011  
    Liquids     Natural Gas     Marketing     Corporate(1)     Total  
    (in millions)  

Total revenue

  $ 612.4      $ 3,695.9      $ 1,120.3      $      $ 5,428.6   

Less: Intersegment revenue

    0.7        748.1        18.9               767.7   
                                       

Operating revenue

    611.7        2,947.8        1,101.4               4,660.9   

Cost of natural gas

           2,593.5        1,097.3               3,690.8   

Environmental costs, net of recoveries

    (10.9     (0.4                   (11.3