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 September 30, 2012

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             to            

Commission file number 1-10934

 

 

ENBRIDGE ENERGY PARTNERS, L.P.

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware   39-1715850

(State or Other Jurisdiction of

Incorporation or Organization)

  (I.R.S. Employer Identification No.)

1100 Louisiana

Suite 3300

Houston, Texas 77002

(Address of Principal Executive Offices) (Zip Code)

(713) 821-2000

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

 

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

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

The registrant had 254,208,428 Class A common units outstanding as of October 31, 2012.

 

 

 


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 nine month periods ended September 30, 2012 and 2011

     1   
  

Consolidated Statements of Comprehensive Income for the three and nine month periods ended September 30, 2012 and 2011

     2   
  

Consolidated Statements of Cash Flows for the nine month periods ended September 30, 2012 and 2011

     3   
  

Consolidated Statements of Financial Position as of September 30, 2012 and December 31, 2011

     4   
  

Notes to the Consolidated Financial Statements

     5   

Item 2.

  

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

     36   

Item 3.

  

Quantitative and Qualitative Disclosures About Market Risk

     62   

Item 4.

  

Controls and Procedures

     65   
  

PART II - OTHER INFORMATION

  

Item 1.

  

Legal Proceedings

     67   

Item 1A.

  

Risk Factors

     67   

Item 6.

  

Exhibits

     67   

Signatures

     68   

Exhibits

     69   

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 includes forward-looking statements, which are statements that frequently use words such as “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “intend,” “may,” “plan,” “position,” “projection,” “should,” “strategy” “target,” “will” and similar words. Although we believe that such forward-looking statements are reasonable based on currently available information, such statements involve risks, uncertainties and assumptions and are not guarantees of performance. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond the Partnership’s ability to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include those discussed in this Quarterly Report on Form 10-Q, our other reports filed with the Securities and Exchange Commission, and: (1) changes in the demand for or the supply of, forecast data for, and price trends related to crude oil, liquid petroleum, natural gas and NGLs, including the rate of development of the Alberta Oil Sands; (2) our ability to successfully complete and finance expansion projects; (3) the effects of competition, in particular, by other pipeline systems; (4) shut-downs or cutbacks at our facilities or refineries, petrochemical plants, utilities or other businesses for which we transport products or to whom we sell products; (5) hazards and operating risks that may not be covered fully by insurance, including those related to Lines 6A and 6B; (6) changes in or challenges to our tariff rates; and (7) changes in laws or regulations to which we are subject, including compliance with environmental and operational safety regulations that may increase costs of system integrity testing and maintenance.

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, 2011.

 

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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
September 30,
    For the nine month
period ended
September 30,
 
     2012     2011     2012     2011  
     (unaudited; in millions, except per unit amounts)  

Operating revenue (Note 10)

   $ 1,564.3     $ 2,372.2     $ 4,934.9     $ 7,033.1  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses

        

Cost of natural gas (Notes 4 and 10)

     1,048.6       1,805.4       3,320.7       5,496.2  

Environmental costs, net of recoveries (Note 9)

     (134.9     56.1       (109.0     44.8  

Oil measurement adjustments (Note 12)

     (2.0     (2.8     (9.1     (61.5

Operating and administrative (Note 9)

     217.3       181.3       627.5       516.0  

Power (Note 10)

     38.0       37.7       116.6       107.2  

Depreciation and amortization (Note 5)

     86.8       78.9       256.5       256.9  
  

 

 

   

 

 

   

 

 

   

 

 

 
     1,253.8       2,156.6       4,203.2       6,359.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating income

     310.5       215.6       731.7       673.5  

Interest expense (Notes 6 and 10)

     83.4       78.7       248.8       236.6  

Other income (Note 9)

     4.7       —          4.4       6.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

Income before income tax expense

     231.8       136.9       487.3       442.9  

Income tax expense (Note 11)

     2.6       2.1       6.4       5.3  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     229.2       134.8       480.9       437.6  

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

     14.0       12.2       42.1       41.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 215.2     $ 122.6     $ 438.8     $ 396.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income allocable to limited partner interests

   $ 172.7     $ 95.9     $ 346.2     $ 322.9  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 0.60     $ 0.36     $ 1.21     $ 1.26  
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average limited partner units outstanding

     289.3       264.6       286.5       257.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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

 

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

      For the three month
period ended September 30,
    For the nine month
period ended September 30,
 
         2012             2011             2012             2011      
     (unaudited; in millions)  

Net income

   $ 229.2     $ 134.8     $ 480.9     $ 437.6  

Other comprehensive loss, net of tax expense (benefit) $(0.1), $0.4, $0.2, and $0.5, respectively (Note 10)

     (44.7     (67.0     (42.6     (128.1
  

 

 

   

 

 

   

 

 

   

 

 

 

Comprehensive income

     184.5       67.8       438.3       309.5  

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

     14.0       12.2       42.1       41.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 170.5     $ 55.6     $ 396.2     $ 268.5  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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

 

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ENBRIDGE ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

     For the nine month
period ended September 30,
 
           2012                 2011        
     (unaudited; in millions)  

Cash provided by operating activities

    

Net income

   $ 480.9     $ 437.6  

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

    

Depreciation and amortization (Note 5)

     256.5       256.9  

Derivative fair value net gains (Note 10)

     (10.4     (53.9

Inventory market price adjustments (Note 4)

     9.8       2.0  

Environmental costs, net of recoveries (Note 9)

     32.2       94.7  

Other (Note 15)

     9.6       12.8  

Changes in operating assets and liabilities:

    

Receivables, trade and other

     (16.8     (1.9

Due from General Partner and affiliates

     2.8       8.8  

Accrued receivables

     125.9       91.5  

Inventory (Note 4)

     21.0       (11.5

Current and long-term other assets (Note 10)

     (12.6     (7.7

Due to General Partner and affiliates

     (1.1     19.1  

Accounts payable and other (Notes 3 and 10)

     6.1       37.2  

Environmental liabilities (Note 9)

     (78.6     (198.7

Accrued purchases

     (138.2     (50.0

Interest payable

     8.8       19.2  

Property and other taxes payable

     12.4       15.3  

Settlement of interest rate derivatives (Note 10)

     —          (18.8
  

 

 

   

 

 

 

Net cash provided by operating activities

     708.3       652.6  
  

 

 

   

 

 

 

Cash used in investing activities

    

Additions to property, plant and equipment (Note 5)

     (1,211.9     (755.8

Changes in construction payables

     72.8       132.2  

Asset acquisitions

     —          (26.7

Joint venture contributions

     (81.7     —     

Other

     2.8       (10.5
  

 

 

   

 

 

 

Net cash used in investing activities

     (1,218.0     (660.8
  

 

 

   

 

 

 

Cash provided by financing activities

    

Net proceeds from unit issuances

     456.2       557.6  

Distributions to partners (Note 7)

     (484.2     (412.6

Repayments to General Partner (Note 8)

     (12.0     (12.4

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

     —          740.7  

Net commercial paper borrowings (Note 6)

     285.0       (509.8

Borrowings from General Partner (Note 8)

     —          7.0  

Contribution from noncontrolling interest (Note 8)

     122.3       3.3  

Distributions to noncontrolling interest (Note 8)

     (47.0     (61.1

Other

     —          (5.7
  

 

 

   

 

 

 

Net cash provided by financing activities

     320.3       307.0  
  

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     (189.4     298.8  

Cash and cash equivalents at beginning of year

     422.9       144.9  
  

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 233.5     $ 443.7  
  

 

 

   

 

 

 

 

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

 

     September 30,
2012
    December 31,
2011
 
     (unaudited; in millions)  
ASSETS   

Current assets

    

Cash and cash equivalents (Note 3)

   $ 233.5     $ 422.9  

Receivables, trade and other, net of allowance for doubtful accounts of $1.5 in 2012 and 2011 (Note 9)

     222.1       235.3  

Due from General Partner and affiliates

     21.2       23.3  

Accrued receivables

     382.0       507.9  

Inventory (Note 4)

     62.8       93.6  

Other current assets (Note 10)

     60.4       36.4  
  

 

 

   

 

 

 
     982.0       1,319.4  

Property, plant and equipment, net (Note 5)

     10,402.5       9,439.4  

Goodwill

     246.7       246.7  

Intangibles, net

     259.5       265.3  

Other assets, net (Note 10)

     180.7       99.3  
  

 

 

   

 

 

 
   $ 12,071.4     $ 11,370.1  
  

 

 

   

 

 

 
LIABILITIES AND PARTNERS’ CAPITAL     

Current liabilities

    

Due to General Partner and affiliates

   $ 53.9     $ 55.0  

Accounts payable and other (Notes 3, 10 and 14)

     570.3       478.6  

Environmental liabilities (Note 9)

     107.1       172.1  

Accrued purchases

     365.0       503.2  

Interest payable

     78.7       69.9  

Property and other taxes payable (Note 11)

     71.8       59.4  

Note payable to General Partner (Note 8)

     12.0       12.0  

Current maturities of long-term debt (Note 6)

     300.0       100.0  
  

 

 

   

 

 

 
     1,558.8       1,450.2  

Long-term debt (Note 6)

     4,901.6       4,816.1  

Note payable to General Partner (Note 8)

     318.0       330.0  

Other long-term liabilities (Notes 9, 10 and 11)

     193.3       161.7  
  

 

 

   

 

 

 
     6,971.7       6,758.0  
  

 

 

   

 

 

 

Commitments and contingencies (Note 9)

    

Partners’ capital (Notes 7 and 8)

    

Class A common units (254,208,428 and 238,043,964 at September 30, 2012 and December 31, 2011, respectively)

     3,708.9       3,386.7  

Class B common units (7,825,500 at September 30, 2012 and December 31, 2011)

     87.5       82.2  

i-units (40,502,828 and 38,566,334 at September 30, 2012 and December 31, 2011, respectively)

     798.8       728.6  

General Partner

     300.7       285.6  

Accumulated other comprehensive income (loss) (Note 10)

     (359.1     (316.5
  

 

 

   

 

 

 

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

     4,536.8       4,166.6  

Noncontrolling interest (Note 8)

     562.9       445.5  
  

 

 

   

 

 

 

Total partners’ capital

     5,099.7       4,612.1  
  

 

 

   

 

 

 
   $ 12,071.4     $ 11,370.1  
  

 

 

   

 

 

 

 

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

 

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ENBRIDGE ENERGY PARTNERS, L.P.

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (unaudited)

1. BASIS OF PRESENTATION

The accompanying unaudited interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America, or GAAP, for interim consolidated financial information and with the instructions to Form 10-Q and Rule 10-01 of Regulation S-X. Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. In the opinion of management, they contain all adjustments, consisting only of normal recurring adjustments, which management considers necessary to present fairly our financial position as of September 30, 2012, our results of operations for the three and nine month periods ended September 30, 2012 and 2011 and our cash flows for the nine month periods ended September 30, 2012 and 2011. We derived our consolidated statement of financial position as of December 31, 2011 from the audited financial statements included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011. Our results of operations for the three and nine month periods ended September 30, 2012 should not be taken as indicative of the results to be expected for the full year due to seasonal fluctuations in the supply of and demand for crude oil, seasonality of portions of our Natural Gas business, timing and completion of our construction projects, maintenance activities, the impact of forward commodity prices and differentials on derivative financial instruments that are accounted for at fair value and the effect of environmental costs and related insurance recoveries on our Lakehead system. Our 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, 2011.

For comparability purposes, we have made reclassifications in our statement of cash flows as of September 30, 2011 to conform to our current year presentation. We reclassified approximately $50.0 million for amounts related to the Line 6B insurance recoveries from “Environmental liabilities” to “Receivables trade and other,” for the nine month period ended September 30, 2011.

2. NET INCOME PER LIMITED PARTNER AND GENERAL PARTNER INTEREST

We allocate our net income among our General Partner, or Enbridge Energy Company, Inc., 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% and 98%, respectively, as set forth in our partnership agreement as follows:

 

Distribution Targets

  

Portion of Quarterly

Distribution Per Unit

   Percentage Distributed to
General Partner
  Percentage Distributed to
Limited partners
 

Minimum Quarterly Distribution

   Up to $0.295    2 %     98 

First Target Distribution

   > $0.295 to $0.35    15 %     85 

Second Target Distribution

   > $0.35 to $0.495    25 %     75 

Over Second Target Distribution

   In excess of $0.495    50 %     50 

 

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

 

     For the three month period
ended September 30,
    For the nine month period
ended September 30,
 
         2012             2011             2012             2011      
     (in millions, except per unit amounts)  

Net income

   $ 229.2     $ 134.8     $ 480.9     $ 437.6  

Less: Net income attributable to noncontrolling interest

     14.0       12.2       42.1       41.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

     215.2       122.6       438.8       396.6  

Less distributions paid:

        

Incentive distributions to our General Partner

     (30.7     (24.7     (85.5     (67.1

Distributed earnings allocated to our General Partner

     (3.4     (3.0     (9.7     (8.5
  

 

 

   

 

 

   

 

 

   

 

 

 

Total distributed earnings to our General Partner

     (34.1     (27.7     (95.2     (75.6

Total distributed earnings to our limited partners

     (164.4     (145.5     (471.5     (416.8
  

 

 

   

 

 

   

 

 

   

 

 

 

Total distributed earnings

     (198.5     (173.2     (566.7     (492.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Underdistributed (Overdistributed) earnings

   $ 16.7     $ (50.6   $ (127.9   $ (95.8
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average limited partner units outstanding

     289.3       264.6       286.5       257.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

Basic and diluted earnings per unit:

        

Distributed earnings per limited partner unit (1) 

   $ 0.57     $ 0.55     $ 1.65     $ 1.62  

Underdistributed (Overdistributed) earnings per limited partner unit (2) 

     0.03       (0.19     (0.44     (0.36
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income per limited partner unit (basic and diluted)

   $ 0.60     $ 0.36     $ 1.21     $ 1.26  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

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

(2) 

Represents the limited partners’ share (98%) of distributions in excess of earnings divided by the weighted average number of limited partner interests outstanding for the period and underdistributed 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 $26.1 million at September 30, 2012 and $30.8 million at December 31, 2011 are included in “Accounts payable and other” on our consolidated statements of financial position.

4. INVENTORY

Our inventory consists of the following:

 

     September 30,
2012
     December 31,
2011
 
     (in millions)  

Materials and supplies

   $ 2.2      $ 2.2  

Crude oil inventory

     12.4        10.7  

Natural gas and NGL inventory

     48.2        80.7  
  

 

 

    

 

 

 
   $ 62.8      $ 93.6  
  

 

 

    

 

 

 

 

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The “Cost of natural gas” on our consolidated statements of income includes charges totaling $0.2 million and $9.8 million for the three and nine month periods ended September 30, 2012 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 to reduce our natural gas and NGLs inventories of $1.8 million and $2.0 million were incurred for the three and nine month periods ended September 30, 2011.

5. PROPERTY, PLANT AND EQUIPMENT

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

 

     September 30,
2012
    December 31,
2011 (1)
 
     (in millions)  

Land

   $ 38.5     $ 37.1  

Rights-of-way

     598.7       564.4  

Pipelines

     6,453.5       6,268.1  

Pumping equipment, buildings and tanks

     1,587.1       1,436.3  

Compressors, meters and other operating equipment

     1,706.8       1,623.2  

Vehicles, office furniture and equipment

     217.9       211.8  

Processing and treating plants

     477.6       456.6  

Construction in progress

     1,590.7       874.3  
  

 

 

   

 

 

 

Total property, plant and equipment

     12,670.8       11,471.8  

Accumulated depreciation

     (2,268.3     (2,032.4
  

 

 

   

 

 

 

Property, plant and equipment, net

   $ 10,402.5     $ 9,439.4  
  

 

 

   

 

 

 

 

(1) 

For comparability purposes, we have made reclassifications of approximately $63.6 million out of the Processing and treating plants category and into the Land, Pumping equipment, buildings and tanks, and Compressors, meters and other operating equipment categories for the December 31, 2011 balances.

Based on our own internal study, with consideration of a third-party consultant’s report, revised depreciation rates for our Anadarko, North Texas and East Texas natural gas systems were implemented effective July 1, 2011. The average remaining service life of these natural gas systems was extended from 29 years to 36 years. The predominant factor contributing to the change in service lives was an increase in the estimated remaining reserves in the regions our natural gas systems serve, due to enhancements in fracturing technologies which will allow producers to have greater access to unconventional natural gas. The new remaining service lives will result in an approximately $34 million annual reduction in depreciation expense, with reductions of $8.5 million for the three month periods ended September 30, 2012 and 2011 and $25.5 million for the nine month period ended September 30, 2012.

6. DEBT

Credit Facilities

In September 2011, we entered into a credit agreement with Bank of America, as administrative agent, and the lenders party thereto, which we refer to as the Credit Facility. The agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $2 billion, a letter of credit subfacility and a swing line subfacility. Effective September 26, 2012, we extended the maturity date to September 26, 2017 and amended it to adjust the base interest rates.

Effective September 30, 2011, our Credit Facility was amended to modify the definition of Consolidated Earnings Before Income Taxes Depreciation and Amortization, or Consolidated EBITDA, as set forth in the terms of our Credit Facility, to increase from $550 million to $650 million, the aggregate amount of the costs

 

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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 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 September 30, 2012, we were in compliance with the terms of our financial covenants.

On July 6, 2012, we entered into a credit agreement with JPMorgan Chase Bank, as administrative agent, and a syndicate of 12 lenders, which we refer to as the 364-Day Credit Facility. The agreement is a committed senior unsecured revolving credit facility pursuant to which the lenders have committed to lend us up to $675 million 1) on a revolving basis for a 364-day period, extendible annually at the lenders’ discretion; and 2) for a 364-day term on a non-revolving basis following the expiration of all revolving periods. We refer to the 364-Day Credit Facility and the Credit Facility as our Credit Facilities.

The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. It is our policy to maintain availability at any time under our Credit Facilities amounts that are at least equal to the amount of commercial paper that we have outstanding at such time. Taking that policy into account, at September 30, 2012, we could borrow $1,888.6 million under the terms of our Credit Facilities, determined as follows:

 

     (in millions)  

Total credit available under Credit Facilities

   $ 2,675.0  

Less: Amounts outstanding under Credit Facilities

     —     

Principal amount of commercial paper outstanding

     560.0  

Letters of credit outstanding

     226.4  
  

 

 

 

Total amount we could borrow at September 30, 2012

   $ 1,888.6  
  

 

 

 

Individual London Inter-Bank Offered Rate, or LIBOR rate, borrowings under the terms of our Credit Facilities may be renewed as LIBOR rate borrowings or as base rate borrowings at the end of each LIBOR rate interest period, which is typically a period of three months or less. These renewals do not constitute new borrowings under the Credit Facilities and do not require any cash repayments or prepayments. For the three and nine month periods ended September 30, 2012 and 2011, we have not renewed any LIBOR rate borrowings or base rate borrowings on a non-cash basis.

Commercial Paper

We have a commercial paper program that provides for the issuance of up to an aggregate principal amount of $1.5 billion of commercial paper 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 September 30, 2012, we had $560.0 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.48%, excluding the effect of our interest rate hedging activities. At December 31, 2011, we had $275.0 million in principal amount of commercial paper outstanding at a weighted average interest rate of 0.44%, excluding the effect of our interest rate hedging activities. Our policy is to limit the commercial paper we issue by the amounts available for us to borrow 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 Credit Facilities. Accordingly, such amounts have been classified as “Long-term debt” in our accompanying consolidated statements of financial position.

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 under our Credit Facilities and prior

 

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credit facilities approximate their fair values at September 30, 2012 and December 31, 2011, respectively, due to the short-term nature and frequent repricing of these obligations. The fair value of our outstanding commercial paper and borrowings under our Credit Facilities are included with our long-term debt obligations below since we have the ability 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. The fair value of our long-term debt obligations is categorized as Level 2 within the fair value hierarchy.

 

     September 30, 2012      December 31, 2011  
     Carrying
Amount
     Fair
Value
     Carrying
Amount
     Fair
Value
 
     (in millions)  

Commercial Paper

   $ 560.0      $ 560.0      $ 275.0      $ 275.0  

7.900% Senior Notes due 2012

     100.0        101.1        100.0        106.1  

4.750% Senior Notes due 2013

     200.0        206.2        199.9        209.6  

5.350% Senior Notes due 2014

     200.0        216.9        200.0        218.9  

5.875% Senior Notes due 2016

     299.9        348.2        299.9        346.2  

7.000% Senior Notes due 2018

     99.9        125.8        99.9        123.8  

6.500% Senior Notes due 2018

     398.8        488.5        398.7        481.5  

9.875% Senior Notes due 2019

     500.0        719.7        500.0        715.1  

5.200% Senior Notes due 2020

     499.9        580.3        499.8        563.0  

4.200% Senior Notes due 2021

     598.9        648.5        598.8        620.8  

7.125% Senior Notes due 2028

     99.8        139.5        99.8        134.6  

5.950% Senior Notes due 2033

     199.7        248.1        199.7        238.1  

6.300% Senior Notes due 2034

     99.8        128.6        99.8        123.5  

7.500% Senior Notes due 2038

     399.0        583.8        399.0        563.5  

5.500% Senior Notes due 2040

     546.3        616.4        546.2        594.7  

8.050% Junior subordinated notes due 2067

     399.6        457.5        399.6        435.5  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

   $ 5,201.6      $ 6,169.1      $ 4,916.1      $ 5,749.9  
  

 

 

    

 

 

    

 

 

    

 

 

 

7. PARTNERS’ CAPITAL

Distribution to Partners

The following table sets forth our distributions, as approved by the board of directors of Enbridge Energy Management, or Enbridge Management, during the nine month period ended September 30, 2012.

 

Distribution
Declaration Date

 

Record Date

 

Distribution
Payment Date

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

January 30, 2012

  February 7, 2012   February 14, 2012    $ 0.5325     $ 180.3     $ 20.5     $   0.4   $   159.4

April 30, 2012

  May 7, 2012   May 15, 2012    $ 0.5325     $ 180.7     $ 20.9     $   0.4   $   159.4

July 30, 2012

  August 7, 2012   August 14, 2012    $ 0.5435     $ 187.5     $ 21.6     $   0.5   $   165.4

 

(1) 

We issued 1,936,494 i-units to Enbridge Management, the sole owner of our i-units, during 2012 in lieu of cash distributions.

(2) 

We retained an amount equal to 2% of the i-unit distribution from our General Partner to maintain its 2% general partner interest in us.

 

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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 nine month periods ended September 30, 2012 and 2011. The noncontrolling interest in the OLP arises from the joint funding arrangements with our General Partner and its affiliate to finance construction of the i) United States portion of the Alberta Clipper crude oil pipeline and related facilities, which we refer to as the Alberta Clipper Pipeline and ii) expansion of our Lakehead system to transport crude oil to destinations in the Midwest United States, which we refer to as the Eastern Access Projects.

 

     For the three month
period ended September 30,
    For the nine month
period ended September 30,
 
          2012             2011             2012             2011      
     (in millions)  

General and limited partner interests

        

Beginning balance

   $ 4,389.9     $ 3,626.6     $ 4,483.1     $ 3,541.8  

Proceeds from issuance of partnership interests, net of costs

     456.2       483.2       458.2       559.2  

Net income

     215.2       122.6       438.8       396.6  

Distributions

     (165.4     (147.4     (484.2     (412.6
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ 4,895.9     $ 4,085.0     $ 4,895.9     $ 4,085.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

Accumulated other comprehensive income (loss)

        

Beginning balance

   $ (314.4   $ (182.8   $ (316.5   $ (121.7

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

     2.8       22.4       25.1       68.5  

Unrealized net loss on derivative financial instruments

     (47.5     (89.4     (67.7     (196.6
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ (359.1   $ (249.8   $ (359.1   $ (249.8
  

 

 

   

 

 

   

 

 

   

 

 

 

Noncontrolling interest

        

Beginning balance

   $ 472.1     $ 454.1     $ 445.5     $ 465.4  

Capital contributions

     91.2       —          122.3       3.3  

Comprehensive income:

        

Net income

     14.0       12.2       42.1       41.0  

Distributions to noncontrolling interest

     (14.4     (17.7     (47.0     (61.1
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance

   $ 562.9     $ 448.6     $ 562.9     $ 448.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total partners’ capital at end of period

   $ 5,099.7     $ 4,283.8     $ 5,099.7     $ 4,283.8  
  

 

 

   

 

 

   

 

 

   

 

 

 

Issuance of Class A Common Units

The following table presents the net proceeds from our Class A common unit issuances for the current year. The proceeds from the September 2012 offering will be used to fund a portion of our capital expansion projects, for general partnership purposes or any combination of such purposes.

 

2012 Issuance Date

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

September

     16,100,000      $ 28.64      $ 446.8      $   9.4   $   456.2

 

(1) 

Net of underwriters’ fees and discounts, commissions and issuance expenses.

(2) 

Contributions made by the General Partner to maintain its 2% general partner interest.

 

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8. RELATED PARTY TRANSACTIONS

Joint Funding Arrangement for Alberta Clipper Pipeline

In July 2009, we entered into a joint funding arrangement to finance the construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge Inc., or Enbridge.

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, which we refer to as the A1 Term Note. At such time we also terminated the A1 Credit Agreement. The A1 Term Note matures on March 15, 2020, bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400 million. The terms of the A1 Term Note are similar to the terms of our 5.20% senior notes due 2020, except that the A1 Term Note has recourse only to the assets of the United States portion of the Alberta Clipper Pipeline and is subordinate to all of our senior indebtedness. Under the terms of the A1 Term Note, we have the ability to increase the principal amount outstanding to finance the debt portion of the Alberta Clipper Pipeline that our General Partner is obligated to make pursuant to the Alberta Clipper Joint Funding Arrangement for any additional costs associated with our construction of the Alberta Clipper Pipeline that we incur after the date the original A1 Term Note was issued. The increases we make to the principal balance of the A1 Term Note will also mature on March 15, 2020. Pursuant to the terms of the A1 Term Note, we are required to make semi-annual payments of principal and accrued interest. The semi-annual principal payments are based upon a straight-line amortization of the principal balance over a 30 year period as set forth in the approved terms of the cost of service recovery model associated with the Alberta Clipper Pipeline, with the unpaid balance due in 2020. The approved terms for the Alberta Clipper Pipeline are described in the “Alberta Clipper United States Term Sheet,” which is included as Exhibit I to the June 27, 2008 Offer of Settlement filed with the Federal Energy Regulatory Commission, or FERC, by the OLP and approved on August 28, 2008 (Docket No. OR08-12-000).

A summary of the cash activity for the A1 Term Note for the nine month periods ended September 30, 2012 and 2011 are as follows:

 

     A1 Term Note
September 30,
 
     2012     2011  
     (in millions)  

Beginning Balance

   $ 342.0     $ 347.4  

Borrowings

     —          7.0  

Repayments

     (12.0     (12.4
  

 

 

   

 

 

 

Ending Balance

   $ 330.0     $ 342.0  
  

 

 

   

 

 

 

Our General Partner also made equity contributions totaling $3.3 million to the OLP during the nine month period ended September 30, 2011 to fund its equity portion of the construction costs associated with the Alberta Clipper Pipeline. No such contributions were made during the nine month period ended September 30, 2012.

We allocated earnings derived from operating the Alberta Clipper Pipeline in the amounts of $14.0 million and $42.1 million to our General Partner for its 66.67% share of the earnings of the Alberta Clipper Pipeline for the three and nine month periods ended September 30, 2012, respectively. We allocated $12.2 million and $41.0 million for the same three and nine month periods ended September 30, 2011, 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.

 

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Distribution to Series AC Interests

The following table presents distributions paid by the OLP to our General Partner and its affiliate during the nine month period ended September 30, 2012, representing the noncontrolling interest in the Series AC and to us, as the holders of the Series AC general and limited partner interests. The distributions were declared by the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and the Series AC interests.

 

Distribution

Declaration Date

  

Distribution

Payment Date

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

January 30, 2012

   February 14, 2012    $ 7.9      $ 15.8      $ 23.7  

April 30, 2012

   May 15, 2012      8.4        16.8        25.2  

July 30, 2012

   August 14, 2012      7.2        14.4        21.6  
     

 

 

    

 

 

    

 

 

 
      $ 23.5      $ 47.0      $ 70.5  
     

 

 

    

 

 

    

 

 

 

Joint Funding Arrangement for Eastern Access Projects

In May 2012, we amended and restated the partnership agreement of the OLP to create a new series of partnership interests, which we refer to as the Series EA partnership interests. Such series of partnership interests are being used to fund the development, construction, financing, ownership and operation of certain projects to expand the capacity of the Lakehead system. Our General Partner indirectly owns 60% of the Series EA partnership interests. We and our affiliates own 40% of the Series EA partnership interests. Before December 31, 2012, we will have the option to reduce our funding and associated economic interest in the projects by up to 15 percentage points down to 25%. Additionally, within one year of the in-service date, scheduled for early 2014, we will also have the option to increase our economic interest held at that time by up to 15 percentage points.

Our General Partner has made equity contributions totaling $91.2 million and $122.3 million to the OLP during the three and nine month periods ended September 30, 2012 respectively, to fund its equity portion of the construction costs associated with the Eastern Access Projects.

9. COMMITMENTS AND CONTINGENCIES

Environmental Liabilities

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

As of September 30, 2012 and December 31, 2011, we had $20.4 million and $31.3 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.

 

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Lakehead Lines 6A & 6B Crude Oil Releases

Line 6B Crude Oil Release

During the second quarter 2012, local authorities allowed the Kalamazoo River and Morrow Lake, which were affected by the Line 6B crude oil release, to be re-opened for recreational use. We continue to perform necessary remediation, restoration and monitoring of the areas affected by the Line 6B crude oil release. All the initiatives we are undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities.

On July 2, 2012, we received a Notice of Probable Violation, or NOPV, from the Pipeline and Hazardous Materials Safety Administration, or PHMSA, related to the Line 6B crude oil release, which resulted in a payment of $3.7 million civil penalty in the third quarter of 2012. We have included the amount of the penalty in our total estimated cost for the Line 6B crude oil release. In addition, on July 10, 2012, the National Transportation Safety Board, or NTSB, presented the results of its investigation into the Line 6B crude oil release and subsequently publicly posted its final report on July 26, 2012.

As of September 30, 2012, we have revised our total cost estimate to $810.0 million, primarily due to an estimate of extended oversight by regulators and additional legal costs associated with various lawsuits, which is an increase of $25.0 million from our estimate as of June 30, 2012. This total estimate is before insurance recoveries and excluding additional fines and penalties which may be imposed by federal, state and local governmental agencies, other than the PHMSA civil penalty described above. On October 3, 2012, we received a letter from the Environmental Protection Agency, or EPA, regarding a proposed order, which we refer to as the Proposed Order, for potential incremental containment and active recovery of submerged oil. We are in discussions with the EPA regarding the agency’s intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities. As such, we have not included significant additional costs related to this Proposed Order in our total cost estimate and it is impracticable to provide an estimate at this time.

For purposes of estimating our expected losses associated with the Line 6B crude oil release, we have included those costs that we considered probable and that could be reasonably estimated at September 30, 2012. Our estimates do not include amounts we have capitalized or any claims associated with the release that may later become evident and is before any insurance recoveries and excludes fines and penalties from other governmental agencies other than the PHMSA civil penalty described above. Our assumptions include, where applicable, estimates of the expected number of days the associated services will be required and rates that we have obtained from contracts negotiated for the respective service and equipment providers. As we receive invoices for the actual personnel, equipment and services, our estimates will continue to be further refined. Our estimates also consider currently available facts, existing technology and presently enacted laws and regulations. These amounts also consider our and other companies’ prior experience remediating contaminated sites and data released by government organizations. Despite the efforts we have made to ensure the reasonableness of our estimates, changes to the recorded amounts associated with this release are possible as more reliable information becomes available. We continue to have the potential of incurring additional costs in connection with this crude oil release due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies in addition to fines and penalties as well as expenditures associated with litigation and settlement of claims.

The material components underlying our 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

   $ 368  

Environmental Consultants

     148  

Professional, regulatory and other

     294  
  

 

 

 

Total

   $ 810  
  

 

 

 

 

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We expect to make payments for additional costs associated with submerged oil and sheen monitoring and recovery operations, including remediation and restoration of the area, air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. We have made payments totaling $691.1 million for costs associated with the Line 6B crude oil release, $120.9 million of which relates to the nine month period ended September 30, 2012. We have a remaining liability of $118.9 million, a majority of which is presented as current, on our consolidated statement of financial position as of September 30, 2012. The forgoing amounts are before insurance recoveries and excluding fines and penalties other than the PHMSA civil penalty described above.

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, the cost estimate remains at approximately $48 million, 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 $46.5 million for costs associated with the Line 6A crude oil release, $1.1 million of which relates to the nine month period ended September 30, 2012. We have a remaining total liability of $1.5 million, a majority of which is presented as current, on our consolidated statement of financial position as of September 30, 2012.

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. We are also pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained.

Lines 6A & 6B Fines and Penalties

Our estimated costs for Line 6A do not include an estimate for fines and penalties at September 30, 2012, which may be imposed by the EPA and PHMSA, in addition to other federal, state and local governmental agencies. At September 30, 2012, our estimated costs to the Line 6B crude oil release include $3.7 million in civil penalties assessed by PHMSA that we paid during the third quarter of 2012, but do not include any other fines or penalties which may be imposed by other governmental agencies. Several factors remain outstanding at the end of the period that we consider critical in estimating the amount of additional 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 potential additional fines and penalties that we could be assessed in connection with each of the releases. As a result, except for the PHMSA civil penalty, 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 in 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 release for Line 6B are covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability. Based on our remediation spending through September 30, 2012, we have exceeded the limits of coverage under this insurance

 

14


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

We recognized $170.0 million of insurance recoveries as reductions to “Environmental costs, net of recoveries” in our consolidated statements of income for the three and nine month periods ended September 30, 2012 for the Line 6B crude oil release. As of September 30, 2012, we have $20.0 million recorded in “Receivable, trade and other” in our consolidated statement of financial position for an insurance payment we received in October 2012. As of September 30, 2012 we have recorded total insurance recoveries of $505.0 million for the Line 6B crude oil release. We expect to record receivables for additional amounts we claim for recovery pursuant to our insurance policies during the period that we deem realization of the claim for recovery to be probable. We recognized $85.0 million and $135.0 million of insurance recoveries, as reductions to environmental costs, for the three and nine month periods ended September 30, 2011, respectively.

Effective May 1, 2012, Enbridge renewed its comprehensive insurance program, through April 30, 2013, with a current liability aggregate limit of $660.0 million, including sudden and accidental pollution liability.

Line 6B Pipeline Integrity Plan

In connection with the restart of Line 6B of our Lakehead system in September 2010, 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.

We filed a supplement to our Facilities Surcharge Mechanism, which became effective on April 1, 2011, when it was approved by the FERC for recovery of $175 million of capital costs and $5 million of operating costs for the 2010 and 2011 Line 6B Pipeline Integrity Plan. The costs associated with the Line 6B Pipeline Integrity Plan, 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.

Line 6B Replacement Program

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 $286.0 million. Our Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. The new segments of pipeline are targeted to be placed in service during 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered through our Facilities Surcharge Mechanism, or FSM, which is part of the system-wide rates of the Lakehead system. We have subsequently revised the scope of this project to increase the diameter of all pipe segments upstream of Stockbridge, Michigan at a cost of approximately $31.0 million, which will bring the total capital for this replacement program to an estimated cost of $317.0 million. The $31.0 million of additional costs will be recovered through the FSM.

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.

 

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Lakehead Line 14 Crude Oil Release

On July 27, 2012, a release of crude oil was detected on Line 14 of our Lakehead system near Grand Marsh, Wisconsin. The estimate of volume of the oil released was approximately 1,200 barrels. We received a Corrective Action Order, or CAO, from PHMSA, on July 30, 2012 followed by an amended CAO, which we refer to as the PHMSA Corrective Action Orders, on August 1, 2012. Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. The pressure restrictions will remain in place until such time we can demonstrate that the root cause of the incident has been remediated.

We have updated our disclosed estimate for repair and remediation related costs associated with this crude oil release to approximately $12.1 million, inclusive of approximately $1.6 million of lost revenue and excluding any fines and penalties. Despite the efforts we have made to ensure the reasonableness of our estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available. We will be pursuing claims under our insurance policy, although we do not expect any recoveries to be significant.

Proceeds from Claim Settlements

In April 2011, 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 in prior years. 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 statement of income for the nine month period ended September 30, 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 30 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 and actions seeking class status. Based on the current status of these cases, we do not expect these actions to be material. On July 2, 2012, PHMSA announced a NOPV related to the Line 6B crude oil release, including a civil penalty of $3.7 million that we paid during the third quarter of 2012.

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

We have accrued a provision for future legal costs and probable losses associated with the Line 6A and Line 6B crude oil releases as described above in 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 of our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and/or forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices. We have hedged a portion of our exposure to variability in future cash flows associated with the risks discussed above through 2018 in accordance with our risk management policies.

Accounting Treatment

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.

In accordance with the applicable authoritative accounting guidance, if a derivative financial instrument does not qualify as a hedge, or is not designated as a hedge, the derivative is marked-to-market each period with the increases and decreases in fair market value recorded in our consolidated statements of income as increases and decreases in “Operating revenue,” “Cost of natural gas” and “Power” for our commodity-based derivatives and “Interest expense” for our interest rate derivatives. Cash flow is only impacted to the extent the actual derivative contract is settled by making or receiving a payment to or from the counterparty or by making or receiving a payment for entering into a contract that exactly offsets the original derivative contract. Typically, we settle our derivative contracts when the physical transaction that underlies the derivative financial instrument occurs.

If a derivative financial instrument qualifies and is designated as a cash flow hedge, which is a hedge of a forecasted transaction or future cash flows, any unrealized mark-to-market gain or loss is deferred in “Accumulated other comprehensive income,” also referred to as AOCI, a component of “Partners’ capital,” until the underlying hedged transaction occurs. To the extent that the hedge instrument is effective in offsetting the transaction being hedged, there is no impact to the income statement until the underlying transaction occurs. At inception and on a quarterly basis, we formally assess whether the hedge contract is highly effective in offsetting changes in cash flows of hedged items. Any ineffective portion of a cash flow hedge’s change in fair market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as hedges and qualify for hedge accounting are included in “Cost of natural gas” for commodity hedges and “Interest expense” for interest rate hedges in the period in which the hedged transaction occurs. Gains and losses deferred in AOCI related to cash flow hedges for which hedge accounting has been discontinued remain in AOCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. Generally, our preference is for our derivative financial instruments to receive hedge accounting treatment whenever possible to mitigate the non-cash earnings volatility that arises from recording the

 

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changes in fair value of our derivative financial instruments through earnings. To qualify for cash flow hedge accounting treatment as set forth in the authoritative accounting guidance, very specific requirements must be met in terms of hedge structure, hedge objective and hedge documentation.

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”, “Power” or “Interest expense” in our consolidated statements of income. These mark-to-market adjustments produce a degree of earnings volatility that can often be significant from period to period, but have no cash flow impact relative to changes in market prices. The cash flow impact occurs when the underlying physical transaction takes place in the future and the associated financial instrument contract settlement is made.

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

Commodity Price Exposures:

 

   

Transportation—In our 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.

 

   

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.

 

   

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

 

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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. In the second quarter 2009, we determined that a sub-group of physical NGL sales contracts with terms allowing for economic net settlement did not qualify for the normal purchases and normal sales, or NPNS, scope exception and are being marked-to-market each period with the changes in fair value recorded in earnings. 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.

 

   

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. As a result, our operating income is subject to additional volatility associated with changes in the fair value of these agreements due to fluctuations in forward power prices.

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

 

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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”

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 September 30,
    For the nine month period
ended September 30,
 
         2012             2011             2012             2011      
           (unaudited; in millions)        

Liquids segment

        

Non-qualified hedges

   $ (9.6   $ 33.7     $ 2.7     $ 38.5  

Natural Gas segment

        

Hedge ineffectiveness

     (3.9     (1.5     1.2       (0.1

Non-qualified hedges

     (20.0     17.0       9.8       16.1  

Marketing

        

Non-qualified hedges

     (0.7     1.6       (3.1     (0.1
  

 

 

   

 

 

   

 

 

   

 

 

 

Commodity derivative fair value net gains (losses)

     (34.2     50.8       10.6       54.4  

Corporate

        

Hedge ineffectiveness

     (0.1     (0.1     0.2       (0.1

Non-qualified interest rate hedges

     (0.2     (0.1     (0.4     (0.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Derivative fair value net gains (losses)

   $ (34.5   $ 50.6     $ 10.4     $ 53.9  
  

 

 

   

 

 

   

 

 

   

 

 

 

Derivative Positions

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

 

     September 30,
2012
    December 31,
2011
 
     (in millions)  

Other current assets

   $ 34.5     $ 20.2  

Other assets, net

     18.7       13.0  

Accounts payable and other

     (178.8     (166.2

Other long-term liabilities

     (163.9     (121.5
  

 

 

   

 

 

 
   $ (289.5   $ (254.5
  

 

 

   

 

 

 

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 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 $41.8 million associated with derivative financial instruments that

 

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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 nine month period ended September 30, 2012, unrealized commodity hedge losses of $3.9 million were de-designated as a result of the hedges no longer meeting hedge accounting criteria. We estimate that approximately $171.2 million, representing unrealized net losses from our cash flow hedging activities based on pricing and positions at September 30, 2012, will be reclassified from AOCI to earnings during the next 12 months.

In connection with our September 2011 issuance of the 2021 Notes, we paid $18.8 million to settle treasury locks we entered to hedge the interest payments on a portion of these obligations through the maturity date of the 2021 Notes. The settlement amount is being amortized from AOCI to “Interest expense” over the respective 10-year term of the 2021 Notes.

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

 

     September 30,
2012
    December 31,
2011
 
     (in millions)  

Counterparty Credit Quality*

    

AAA

   $ —        $ (0.2

AA

     (119.4     (98.4

A

     (172.4     (160.7

Lower than A

     2.3       4.8  
  

 

 

   

 

 

 
   $ (289.5   $ (254.5
  

 

 

   

 

 

 

 

* 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 decreased. 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 would include any cash collateral received in the balances listed above, however, as of September 30, 2012 and December 31, 2011 we are holding no cash collateral on our asset exposures. 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 and 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

 

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are likewise required to post collateral on their liability (our asset) exposures, also determined by tiered contractual collateral thresholds. Counterparty collateral may consist of cash or letters of credit, both of which must be fulfilled with immediately available funds.

In the event that our credit ratings were to decline 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 September 30, 2012, we would have been required to provide additional letters of credit in the amount of $62.0 million.

At September 30, 2012 and December 31, 2011, we had credit concentrations in the following industry sectors, as presented below:

 

     September 30,
2012
    December 31,
2011
 
     (in millions)  

United States financial institutions and investment banking entities

   $ (206.9   $ (163.6

Non-United States financial institutions

     (93.0     (88.7

Other

     10.4       (2.2
  

 

 

   

 

 

 
   $ (289.5   $ (254.5
  

 

 

   

 

 

 

We are holding no cash collateral on our asset exposures, and we have provided letters of credit totaling $225.8 million and $173.2 million relating to our liability exposures pursuant to the margin thresholds in effect at September 30, 2012 and December 31, 2011, respectively, under our ISDA® agreements.

 

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Gross derivative balances are presented below before the effects of collateral received or posted and without the effects of master netting arrangements. Both our assets and liabilities are adjusted for non-performance risk, which is statistically derived. This credit valuation adjustment model considers existing derivative asset and liability balances in conjunction with contractual netting and collateral arrangements, current market data such as credit default swap rates and bond spreads and probability of default assumptions to quantify an adjustment to fair value. For credit modeling purposes, collateral received is included in the calculation of our assets, while any collateral posted is excluded from the calculation of the credit adjustment. Our credit exposure for these over-the-counter derivatives is directly with our counterparty and continues until the maturity or termination of the contracts. 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

 
   

Financial Position
Location

  Fair Value at    

Financial Position

Location

  Fair Value at  
    September 30,
2012
    December 31,
2011
      September 30,
2012
    December 31,
2011
 
    (in millions)  

Derivatives designated as hedging instruments (1)

           

Interest rate contracts

  Other current assets   $ —        $ —        Accounts payable and other   $ (171.8   $ (134.1

Interest rate contracts

  Other assets, net     0.6       0.2     Other long-term liabilities     (162.3     (109.4

Commodity contracts

  Other current assets     18.1       6.4     Accounts payable and other     (11.0     (30.5

Commodity contracts

  Other assets, net     9.4       11.4     Other long-term liabilities     (7.2     (25.9
   

 

 

   

 

 

     

 

 

   

 

 

 
      28.1       18.0         (352.3     (299.9
   

 

 

   

 

 

     

 

 

   

 

 

 
           

Derivatives not designated as hedging instruments

           

Interest rate contracts

  Other current assets     3.8       4.8     Accounts payable and other     (3.5     (4.4

Interest rate contracts

  Other assets, net     —          2.5     Other long-term liabilities     —          (2.3

Commodity contracts

  Other current assets     33.8       31.7     Accounts payable and other     (13.6     (19.9

Commodity contracts

  Other assets, net     15.7       16.4     Other long-term liabilities     (1.5     (1.4
   

 

 

   

 

 

     

 

 

   

 

 

 
      53.3       55.4         (18.6     (28.0
   

 

 

   

 

 

     

 

 

   

 

 

 

Total derivative instruments

    $ 81.4     $ 73.4       $ (370.9   $ (327.9
   

 

 

   

 

 

     

 

 

   

 

 

 

 

(1) 

Includes items currently designated as hedging instruments. Excludes the portion of de-designated hedges which may have a component remaining in AOCI.

 

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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 September 30, 2012

     

Interest rate contracts

  $ (23.5   Interest expense   $ (7.4   Interest expense   $ (0.1 )

Commodity contracts

    (22.9   Cost of natural gas     4.6     Cost of natural gas     (3.9
 

 

 

     

 

 

     

 

 

 

Total

  $ (46.4     $ (2.8     $ (4.0
 

 

 

     

 

 

     

 

 

 

For the three month period ended September 30, 2011

     

Interest rate contracts

  $ (141.8   Interest expense   $ (7.0   Interest expense   $ (0.1

Commodity contracts

    89.2     Cost of natural gas     (15.4   Cost of natural gas     (1.4
 

 

 

     

 

 

     

 

 

 

Total

  $ (52.6     $ (22.4     $ (1.5
 

 

 

     

 

 

     

 

 

 

For the nine month period ended September 30, 2012

     

Interest rate contracts

  $ (90.4   Interest expense   $ (21.7   Interest expense   $ 0.2  

Commodity contracts

    47.2     Cost of natural gas     (3.4   Cost of natural gas     1.2  
 

 

 

     

 

 

     

 

 

 

Total

  $ (43.2     $ (25.1     $ 1.4  
 

 

 

     

 

 

     

 

 

 

For the nine month period ended September 30, 2011

     

Interest rate contracts

  $ (168.7   Interest expense   $ (20.4   Interest expense   $ (0.1

Commodity contracts

    59.9     Cost of natural gas     (48.1   Cost of natural gas     (0.1
 

 

 

     

 

 

     

 

 

 

Total

  $ (108.8     $ (68.5     $ (0.2
 

 

 

     

 

 

     

 

 

 

 

(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 September 30,
    For the nine month period
ended September 30,
 
           2012     2011     2012     2011  

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   $ (0.1   $ (0.4   $ (0.4

Commodity contracts

   Operating revenue      (9.8     33.3       2.7       38.5  

Commodity contracts

   Power      0.2       0.4       —          —     

Commodity contracts

   Cost of natural gas      (20.7     18.6       6.7       16.0  
     

 

 

   

 

 

   

 

 

   

 

 

 

Total

      $ (30.5   $ 52.2     $ 9.0     $ 54.1  
     

 

 

   

 

 

   

 

 

   

 

 

 

 

(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.

 

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Table of Contents

Gross to Net Presentation Reconciliation of Derivative Assets and Liabilities

 

     September 30, 2012     December 31, 2011  
     Assets     Liabilities     Total     Assets     Liabilities     Total  
     (in millions)  

Fair value of derivatives—gross presentation

   $ 81.4     $ (370.9   $ (289.5   $ 73.4     $ (327.9   $ (254.5

Effects of netting agreements

     (28.2     28.2       —          (40.2     40.2       —     
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Fair value of derivatives—net presentation

   $ 53.2     $ (342.7   $ (289.5   $ 33.2     $ (287.7   $ (254.5
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Inputs to Fair Value Derivative Instruments

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2012 and December 31, 2011. 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.

 

     September 30, 2012     December 31, 2011  
     Level 1      Level 2     Level 3      Total     Level 1      Level 2     Level 3     Total  
     (in millions)  

Interest rate contracts

   $ —         $ (333.2   $ —         $ (333.2   $ —         $ (242.6   $ —        $ (242.6

Commodity contracts:

                   

Financial

     —           6.0       20.6        26.6       —           (10.2     (15.9     (26.1

Physical

     —           —          5.4        5.4       —           —          4.2       4.2  

Commodity options

     —           —          11.7        11.7       —           —          10.0       10.0  
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Total

   $ —         $ (327.2   $ 37.7      $ (289.5   $ —         $ (252.8   $ (1.7   $ (254.5
  

 

 

    

 

 

   

 

 

    

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Qualitative Information about Level 3 Fair Value Measurements

Data from pricing services and published indices are used to value our Level 3 derivative instruments, which are fair-valued on a recurring basis. We may also use these inputs with internally developed methodologies that result in our best estimate of fair value. The inputs listed in the table below would have a direct impact on the fair values of the listed instruments. The significant unobservable inputs used in the fair value measurement of the commodity derivatives (Natural Gas, NGL’s, Crude and Power) are forward commodity prices. The significant unobservable inputs used in determining the fair value measurement of options are price and volatility. Increases/(decreases) in the forward commodity price in isolation would result in significantly higher/(lower) fair values for long positions, with offsetting impacts to short positions. Increases/(decreases) in volatility would increase/(decrease) the value for the holder of the option. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the credit valuation adjustment would decrease the fair value of the positions.

 

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Table of Contents

Quantitative Information About Level 3 Fair Value Measurements

 

    Fair Value at
September 30,
2012 (2)
    Valuation
Technique
  Unobservable Input   Range (1)        

Contract Type

        Lowest     Highest     Weighted
Average
    Units  
    (in millions)                                  

Commodity Contracts - Financial

             

Natural Gas

  $ 8.1     Market Approach   Forward Gas Price     2.72       4.44       3.65       MMBtu   

Crude Oil

  $ 0.3     Market Approach   Forward Crude Price     80.02       96.04       85.56       Bbl   

NGLs

  $ 12.2     Market Approach   Forward NGL Price     0.19       2.02       1.31       Gal   

Commodity Contracts - Physical

             

Natural Gas

  $ 1.6     Market Approach   Forward Gas Price     2.75       4.72       3.89       MMBtu   

Crude Oil

  $ 1.6     Market Approach   Forward Crude Price     72.30       113.29       92.67       Bbl   

NGLs

  $ 3.5     Market Approach   Forward NGL Price     0.02       2.49       1.16       Gal   

Power

  $ (1.3   Market Approach   Forward Power Price     27.17       36.37       32.67       MWh   

Commodity Options

             

Natural Gas, Crude and NGLs

  $ 11.7     Option Model   Option Volatility     26     110     47  
 

 

 

             

Total Fair Value

  $ 37.7              

 

(1) 

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

(2) 

Fair values are presented in millions of dollars and include credit valuation adjustments of approximately $0.4 million of losses.

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, 2012 to September 30, 2012. No transfers of assets between any of the Levels occurred during the period.

 

     Commodity
Financial
Contracts
    Commodity
Physical
Contracts
    Commodity
Options
    Total  
     (in millions)  

Beginning balance as of January 1, 2012

   $ (15.9   $ 4.2     $ 10.0     $ (1.7

Transfer out of Level 3 (1)

     —          —          —          —     

Gains or losses

        

Included in earnings (or changes in net assets)

     8.8       22.0       9.8       40.6  

Included in other comprehensive income

     39.4       —          (0.1     39.3  

Purchases, issuances, sales and settlements

        

Purchases

     —          —          2.1       2.1  

Settlements (2)

     (11.7     (20.8     (10.1     (42.6
  

 

 

   

 

 

   

 

 

   

 

 

 

Ending balance as September 30, 2012

   $ 20.6     $ 5.4     $ 11.7     $ 37.7  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 24.9     $ 4.8     $ 6.3     $ 36.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

Amounts reported in operating revenue

   $ 0.3     $ —        $ —        $ 0.3  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(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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Table of Contents

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 September 30, 2012 and December 31, 2011.

 

   

At September 30, 2012

    At December 31, 2011  
              Wtd. Average  Price (2)     Fair Value (3)     Fair Value (3)  
   

Commodity

  Notional (1)     Receive     Pay     Asset     Liability     Asset     Liability  

Portion of contracts maturing in 2012

               

Swaps

               

Receive variable/pay fixed

  Natural Gas     859,638     $ 3.25     $ 4.49     $ 0.2     $ (1.3   $   —      $ (8.1
  NGL     108,000     $ 59.59     $ 56.98     $ 0.5     $ (0.2   $   0.4   $ —     
  Crude Oil     85,000     $ 92.75     $ 92.22     $ —        $ —        $   —      $ —     

Receive fixed/pay variable

  Natural Gas     1,193,244     $ 4.38     $ 3.33     $ 1.3     $ (0.1   $   7.1   $ —     
  NGL     1,028,360     $ 59.10     $ 54.51     $ 7.0     $ (2.3   $   6.3   $ (20.6
  Crude Oil     585,292     $ 90.25     $ 91.96     $ 1.8     $ (2.8   $   3.5   $ (15.6

Receive variable/pay variable

  Natural Gas     25,217,278     $ 3.19     $ 3.18     $ 0.8     $ (0.5   $   2.8   $ (0.8

Physical Contracts

               

Receive variable/pay fixed

  NGL     80,000     $ 57.85     $ 60.83     $ —        $ (0.3   $   0.3   $ —     
  Crude Oil     73,000     $ 92.56     $ 96.21     $ —        $ (0.3   $   0.2   $ (0.3

Receive fixed/pay variable

  NGL     294,999     $ 41.90     $ 41.89     $ 0.3     $ (0.3   $   0.3   $ (1.0
  Crude Oil     146,000     $ 95.76     $ 92.77     $ 0.4     $ —        $   0.1   $ (0.6

Receive variable/pay variable

  Natural Gas     10,349,133     $ 3.22     $ 3.19     $ 0.3     $ —        $   1.2   $ —     
  NGL     3,950,067     $ 45.37     $ 44.60     $ 5.9     $ (2.8   $   8.8   $ (3.8
  Crude Oil     1,154,616     $ 93.41     $ 92.19     $ 4.1     $ (2.7   $   1.5   $ (1.9

Pay fixed

  Power (4)     14,004     $ 29.71     $ 40.23     $ —        $ (0.2   $   —      $ (0.5

Portion of contracts maturing in 2013

               

Swaps

               

Receive variable/pay fixed

  Natural Gas     1,810,211     $ 3.71     $ 3.42     $ 0.7     $ (0.1   $   —      $ (0.1
  NGL     90,000     $ 84.07     $ 73.79     $ 0.9     $ —        $   —      $ —     

Receive fixed/pay variable

  Natural Gas     4,893,700     $ 4.95     $ 3.71     $ 6.3     $ (0.2   $   5.9   $ —     
  NGL     2,464,610     $ 55.66     $ 53.90     $ 9.6     $ (5.3   $   0.5   $ (8.7
  Crude Oil     1,702,935     $ 91.78     $ 93.71     $ 6.0     $ (9.3   $   3.7   $ (10.0

Receive variable/pay variable

  Natural Gas     45,206,000     $ 3.78     $ 3.75     $ 1.1     $ (0.1   $   0.8   $ (0.1

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     13,153,882     $ 3.81     $ 3.76     $ 0.7     $ —        $   0.5   $ —     
  NGL     1,201,223     $ 60.41     $ 59.77     $ 0.9     $ (0.1   $   0.4   $ (0.1
  Crude Oil     1,200     $ 93.79     $ 73.79     $ —        $ —        $   —      $ —     

Pay fixed

  Power (4)     42,924     $ 32.40     $ 42.82     $ —        $ (0.4   $   —      $ (0.3

Portion of contracts maturing in 2014

               

Swaps

               

Receive variable/pay fixed

  Natural Gas     21,870     $ 4.16     $ 5.22     $ —        $ —        $   —      $ —     

Receive fixed/pay variable

  Natural Gas     912,500     $ 4.09     $ 4.18     $ —        $ (0.1   $   —      $ —     
  NGL     490,925     $ 69.18     $ 67.38     $ 1.7     $ (0.8   $   0.8   $ (1.9
  Crude Oil     1,301,955     $ 94.21     $ 91.49     $ 5.8     $ (2.3   $   4.9   $ (3.1

Receive variable/pay variable

  Natural Gas     7,212,500     $ 4.19     $ 4.17     $ 0.2     $ —        $   0.1   $ —     

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     8,731,275     $ 4.22     $ 4.17     $ 0.5     $ —        $   0.1   $ —     

Pay fixed

  Power (4)     58,608     $ 33.57     $ 46.58     $ —        $ (0.8   $   —      $ (0.5

Portion of contracts maturing in 2015

               

Swaps

               

Receive fixed/pay variable

  NGL     109,500     $ 88.36     $ 80.17     $ 1.0     $ (0.1   $   0.7   $ (0.2
  Crude Oil     865,415     $ 97.72     $ 89.11     $ 7.4     $ (0.1   $   6.0   $ (0.4

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     6,013,425     $ 4.43     $ 4.37     $ 0.4     $ —        $   0.1   $ —     

Portion of contracts maturing in 2016

               

Swaps

               

Receive fixed/pay variable

  Crude Oil     45,750     $ 99.31     $ 87.60     $ 0.5     $ —        $   0.4   $ —     

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     783,240     $ 4.67     $ 4.55     $ 0.1     $ —        $   0.1   $ —     

 

(1) 

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

(2) 

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

(3) 

The fair value is determined based on quoted market prices at September 30, 2012 and December 31, 2011, 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 $0.8 million of losses at September 30, 2012 and December 31, 2011.

(4) 

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

 

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Table of Contents

The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2012 and December 31, 2011.

 

    At September 30, 2012     At December 31, 2011  
              Strike
Price (2)
    Market
Price (2)
    Fair Value (3)     Fair Value (3)  
    Commodity   Notional (1)         Asset     Liability     Asset     Liability  

Portion of option contracts maturing in 2012

  

         

Puts (purchased)

  NGL     602,784     $ 39.92     $ 30.79     $ 6.7     $ —        $   7.3   $ —     
  Crude Oil     16,100     $ 99.00     $ 92.73     $ 0.1     $ —        $   0.7   $ —     

Portion of option contracts maturing in 2013

  

         

Puts (purchased)

  Natural Gas     1,642,500     $ 4.18     $ 3.70     $ 1.1     $ —        $   1.2   $ —     
  NGL     457,000     $ 32.29     $ 29.92     $ 3.8     $ —        $   0.9   $ —     

 

(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 September 30, 2012 and December 31, 2011, 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 September 30, 2012 and at December 31, 2011.

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.

 

                    Fair Value (2) at  

Date of Maturity & Contract Type

  Accounting Treatment   Notional     Average Fixed  Rate (1)     September 30,
2012
    December 31,
2011
 
              (dollars in millions)        

Contracts maturing in 2013

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 800       3.24   $ (28.5   $ (42.2

Interest Rate Swaps—Pay Fixed

  Non-qualifying   $ 125       4.35   $ (3.5   $ (6.8

Interest Rate Swaps—Pay Float

  Non-qualifying   $ 125       4.75   $ 3.8     $ 7.5  

Contracts maturing in 2014

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 200       0.56   $ (0.6   $ 0.2  

Contracts maturing in 2015

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 300       2.43   $ (6.6   $ (4.7

Contracts maturing in 2017

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 500       2.21   $ (16.1   $ (5.8

Contracts maturing in 2018

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 500       2.08   $ (1.8   $ —     

Contracts settling prior to maturity

         

2012—Pre-issuance Hedges

  Cash Flow Hedge   $ 600       4.56   $ (157.7   $ (123.7

2013—Pre-issuance Hedges

  Cash Flow Hedge   $ 500       3.98   $ (87.9   $ (63.1

2014—Pre-issuance Hedges

  Cash Flow Hedge   $ 750       3.15   $ (52.6   $ (23.4

2016—Pre-issuance Hedges

  Cash Flow Hedge   $ 500       2.87   $ 2.2     $ —     

 

(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 September 30, 2012 and December 31, 2011, 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 $16.1 million of gains at September 30, 2012 and $19.4 million of gains at December 31, 2011.

 

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Table of Contents

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 State of Texas. On May 25, 2011, the Governor of Michigan signed legislation implementing a new corporate income tax system. The new tax system became effective January 1, 2012 and repealed the Michigan Business Tax, or MBT, which imposed tax on individuals, LLCs, trusts, partnerships, S corporations, and C corporations and replaced 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.

We computed our income tax expense for 2012, by applying a Texas state income tax rate to modified gross margin and for 2011; we applied an additional Michigan state income tax rate to modified gross receipts. The Texas state income tax rate was 0.5% for the nine month periods ended September 30, 2012 and 2011. The Michigan state income tax rate was 0.2% for the nine month period ended September 30, 2011. Our income tax expense is $2.6 million and $2.1 million and $6.4 million and $5.3 million for the three and nine month periods ended September 30, 2012 and 2011, respectively.

At September 30, 2012 and December 31, 2011, we have included a current income tax payable of $5.4 million and $7.2 million in “Property and other taxes payable,” respectively. In addition, at September 30, 2012 and December 31, 2011, we have included a deferred income tax liability of $3.1 million and $2.8 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.

In June 2011, we recognized $52.2 million from the settlement of a dispute with a shipper on our Lakehead crude oil pipeline system. We received the cash for that settlement in July 2011. The dispute related to oil measurement adjustments we had previously recognized in prior years and was therefore recorded to “Oil measurement adjustments,” as reduction to operating expenses, for the nine month period ended September 30, 2011 in our consolidated statements of income. There were no material oil measurement adjustments for the three and nine month periods ended September 30, 2012.

 

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Table of Contents

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, collectively comprised of our senior management, 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 September 30, 2012  
     Liquids     Natural Gas      Marketing     Corporate (1)     Total  
     (in millions)  

Total revenue

   $ 329.5     $ 1,109.2      $ 375.0     $ —        $ 1,813.7  

Less: Intersegment revenue

     0.5       244.9        4.0       —          249.4  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Operating revenue

     329.0       864.3        371.0       —          1,564.3  

Cost of natural gas

     —          677.5        371.1       —          1,048.6  

Environmental costs, net of recoveries

     (134.9     —           —          —          (134.9

Oil measurement adjustments

     (2.0     —           —          —          (2.0

Operating and administrative

     98.6       116.4        1.8       0.5       217.3  

Power

     38.0       —           —          —          38.0  

Depreciation and amortization

     52.5       34.3        —          —          86.8  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 
     52.2       828.2        372.9       0.5       1,253.8  

Operating income (loss)

     276.8       36.1        (1.9     (0.5     310.5  

Interest expense

     —          —           —          83.4       83.4  

Other income

     —          —           —          4.7       4.7  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income tax expense

     276.8       36.1        (1.9     (79.2     231.8  

Income tax expense

     —          —           —          2.6       2.6  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

Net income (loss)

     276.8       36.1        (1.9     (81.8     229.2  

Less: Net income attributable to the noncontrolling interest

     —          —           —          14.0       14.0  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

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

   $ 276.8     $ 36.1      $ (1.9   $ (95.8   $ 215.2  
  

 

 

   

 

 

    

 

 

   

 

 

   

 

 

 

 

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

Total revenue

  $ 363.3     $ 1,832.1     $ 584.2     $ —        $ 2,779.6  

Less: Intersegment revenue

    0.3       395.7       11.4       —          407.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating revenue

    363.0       1,436.4       572.8       —          2,372.2  

Cost of natural gas

    —          1,233.3       572.1       —          1,805.4  

Environmental costs, net of recoveries

    56.1       —          —          —          56.1  

Oil measurement adjustments

    (2.8     —          —          —          (2.8

Operating and administrative

    74.4       104.5       1.9       0.5       181.3  

Power

    37.7       —          —          —          37.7  

Depreciation and amortization

    49.2       29.7       —          —          78.9  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    214.6       1,367.5       574.0       0.5       2,156.6  

Operating income (loss)

    148.4       68.9       (1.2     (0.5     215.6  

Interest expense

    —          —          —          78.7       78.7  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income tax expense

    148.4       68.9       (1.2     (79.2     136.9  

Income tax expense

    —          —          —          2.1       2.1  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

    148.4       68.9       (1.2     (81.3     134.8  

Less: Net income attributable to the noncontrolling interest

    —          —          —          12.2       12.2  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

  $ 148.4     $ 68.9     $ (1.2   $ (93.5   $ 122.6  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(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 nine month period ended September 30, 2012  
    Liquids     Natural Gas     Marketing     Corporate  (1)     Total  
    (in millions)  

Total revenue

  $ 1,015.6     $ 3,595.5     $ 998.2     $ —        $ 5,609.3  

Less: Intersegment revenue

    1.7       655.5       17.2       —          674.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating revenue

    1,013.9       2,940.0       981.0       —          4,934.9  

Cost of natural gas

    —          2,334.8       985.9       —          3,320.7  

Environmental costs, net of recoveries

    (109.0     —          —          —          (109.0

Oil measurement adjustments

    (9.1     —          —          —          (9.1

Operating and administrative

    276.4       344.6       5.1       1.4       627.5  

Power

    116.6       —          —          —          116.6  

Depreciation and amortization

    155.4       101.1       —          —          256.5  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
    430.3       2,780.5       991.0       1.4       4,203.2  

Operating income (loss)

    583.6       159.5       (10.0     (1.4     731.7  

Interest expense

    —          —          —          248.8       248.8  

Other income

    —          —          —          4.4       4.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income tax expense

    583.6       159.5       (10.0     (245.8     487.3  

Income tax expense

    —          —          —          6.4       6.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

    583.6       159.5       (10.0     (252.2     480.9  

Less: Net income attributable to the noncontrolling interest

    —          —          —          42.1       42.1  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

  $ 583.6     $ 159.5     $ (10.0   $ (294.3   $ 438.8  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

  $ 6,928.8     $ 4,803.6     $ 144.1     $ 194.9     $ 12,071.4  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures (excluding acquisitions)

  $ 880.1     $ 321.0     $ —        $ 10.8     $ 1,211.9  
 

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

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

Total revenue

   $ 975.7     $ 5,528.0     $ 1,704.5     $ —        $ 8,208.2  

Less: Intersegment revenue

     1.0       1,143.8       30.3       —          1,175.1  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Operating revenue

     974.7       4,384.2       1,674.2       —          7,033.1  

Cost of natural gas

     —          3,826.8       1,669.4       —          5,496.2  

Environmental costs, net of recoveries

     45.2       (0.4     —          —          44.8  

Oil measurement adjustments

     (61.5     —          —          —          (61.5

Operating and administrative

     218.5       289.8       5.2       2.5       516.0  

Power

     107.2       —          —          —          107.2  

Depreciation and amortization

     146.5       110.4       —          —          256.9  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
     455.9       4,226.6       1,674.6       2.5       6,359.6  

Operating income (loss)

     518.8       157.6       (0.4     (2.5     673.5  

Interest expense

     —          —          —          236.6       236.6  

Other income

     —          —          —          6.0       6.0  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Income (loss) from continuing operations before income tax expense

     518.8       157.6       (0.4     (233.1     442.9  

Income tax expense

     —          —          —          5.3       5.3  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Net income (loss)

     518.8       157.6       (0.4     (238.4     437.6  

Less: Net income attributable to the noncontrolling interest

     —          —          —          41.0       41.0  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 518.8     $ 157.6     $ (0.4   $ (279.4   $ 396.6  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Total assets

   $ 6,050.6     $ 4,682.4     $ 209.7     $ 379.9     $ 11,322.6  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

Capital expenditures (excluding acquisitions)

   $ 444.9     $ 302.7     $ —        $ 8.2     $ 755.8  
  

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(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.

14. REGULATORY MATTERS

Regulatory Accounting

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

 

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Southern Access Pipeline

For the three months ended September 30, 2012, power cost adjustments within our Southern Access agreement resulted in a favorable net revenue position. As a result, for the three month period ended September 30, 2012, we adjusted our revenues by a net increase of $4.2 million on our consolidated statements of income with a corresponding decrease to the regulatory liability on our consolidated statements of financial position at September 30, 2012. However, for the nine month period ended September 30, 2012, we had a net over collection of revenue for our Southern Access Pipeline because the actual volumes were higher than the forecast volumes used to calculate the toll surcharge, partially offset by the power cost adjustment described above. As a result, for the nine month period ended September 30, 2012, we adjusted our revenues by a net reduction of $4.4 million on our consolidated statements of income with a corresponding increase in the regulatory liability on our consolidated statements of financial position at September 30, 2012 for the differences in these transportation volumes. The amounts will be included in our tolls beginning April 2013 when we update our transportation rates to account for the higher than estimated delivered volumes.

For 2011, we over collected revenue for our Southern Access Pipeline because the actual volumes were higher than the forecast volumes used to calculate the toll surcharge. In addition, the actual costs recognized in 2011 were lower than the forecasted costs used to calculate the toll charge. As a result, in 2011, we reduced our revenues for the amounts we over collected and recorded a regulatory liability. We began to amortize this regulatory liability on a straight line basis during 2012 to recognize the amounts we previously over collected. For the three and nine month periods ended September 30, 2012, we increased our revenues by $5.0 million and $14.1 million, respectively, on our consolidated statement of income with a corresponding amount reducing the regulatory liability on our consolidated statement of financial position at September 30, 2012. At September 30, 2012 and December 31, 2011, we had a $5.0 million and $19.1 million in regulatory liabilities, respectively, on our consolidated statements of financial position related to this over collection. We began to reimburse these amounts to our customers when we updated our transportation rates to account for the higher delivered volumes and lower costs than estimated starting in April 2012.

Alberta Clipper Pipeline

For 2012, we have over collected revenue on our Alberta Clipper Pipeline because the actual volumes were higher than the forecast volumes used to calculate the toll surcharge. As a result, for the three and nine month periods ended September 30, 2012, we reduced our revenues by $1.9 million and $14.7 million, respectively, on our consolidated statement of income with a corresponding increase in the regulatory liability on our consolidated statement of financial position at September 30, 2012 for the differences in transportation volumes. The amounts will be refunded through our tolls beginning April 2013 when we update our transportation rates to account for the higher delivered volumes and higher costs than estimated.

During 2011, we over collected revenue on our Alberta Clipper Pipeline because the actual volumes were higher than forecasted volumes used to calculate the toll charge. As a result, in 2011 we reduced our revenues for the amounts we over collected and recorded a regulatory liability. We began to amortize this regulatory liability on a straight line basis during 2012 to recognize the amounts we previously over collected. For the three and nine month periods ended September 30, 2012, we increased our revenues by $6.5 million and $18.1 million, respectively, on our consolidated statement of income with a corresponding amount reducing the regulatory liability on our consolidated statement of financial position at September 30, 2012. As of September 30, 2012 and December 31, 2011, we had regulatory liabilities of $6.4 million and $24.5 million, respectively, in our consolidated statements of financial position for the difference in volumes. The amounts are being refunded to our customers through transportation rates, which became effective in April 2012.

Other Contractual Obligations

Southern Access Pipeline

We have entered into certain contractual obligations with our customers on the Southern Access Pipeline in which a portion of the revenue earned on volumes above certain predetermined shipment levels, or qualifying

 

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volumes, are returned to the shippers through future rate adjustments. We record the assets and liabilities associated with this contractual obligation in “Other current assets” and “Accounts payable and other,” respectively, on our consolidated statements of financial position. We amortize this contractual obligation on a straight line basis in the following year. At September 30, 2012 and December 31, 2011, we had $11.5 million and $2.8 million, respectively, in qualifying volume liabilities related to the Southern Access Pipeline on our statements of financial position.

For 2011, we also incurred liabilities related to contractual obligations with our customers on the Southern Access Pipeline related to qualifying volumes. As a result, in 2011 we reduced our revenues for the amounts due back to our shippers and recorded a liability for the contractual obligation. We amortize the liability on a straight line basis in the following year. For the nine month periods ended September 30, 2012 and 2011, we increased our revenues by $2.2 million and $3.6 million, respectively, on our consolidated statements of income with a corresponding amount reducing the contractual obligation on our consolidated statements of financial position.

Alberta Clipper Pipeline

A portion of the rates we charge our customers includes an estimate for annual property taxes. If the estimated property tax we collect from our customers is significantly higher than the actual property tax imposed, we are contractually obligated to refund 50% of the property tax over collection to our customers. At September 30, 2012 and December 31, 2011, we had $6.2 million and $7.3 million, respectively, in property tax over collection liabilities related to our Alberta Clipper Pipeline on our statements of financial position.

For 2011, we also incurred liabilities related to this contractual obligation on the Alberta Clipper Pipeline. As a result, in 2011, we reduced revenues for the amounts due back to our shippers and recorded a liability for the contractual obligation. We amortize the liability on a straight line basis in the following year. For the nine month periods ended September 30, 2012 and 2011, we increased our revenues by $5.4 million and $6.5 million, respectively, on our consolidated statements of income with a corresponding amount reducing the contractual obligation on our consolidated statements of financial position.

Regulatory Liability for Southern Lights Pipeline In-Service Delay

In December 2006, as part of the regulatory approval process for its pipeline, Enbridge Pipelines (Southern Lights) L.L.C., or Southern Lights, agreed to the request made by the Canadian Association of Petroleum Producers, referred to as CAPP, to delay the in-service date of its pipeline from January 1, 2010 to July 1, 2010. In exchange for Southern Light’s postponement of the in-service date of its pipeline, CAPP agreed to reimburse Southern Lights for any carrying costs incurred during this period as a result of the delayed in-service date. The carrying costs were collected by us through the transportation rates charged on our Lakehead system beginning on April 1, 2010 and passed through to Southern Lights. As of September 30, 2012, we had $14.8 million recorded as a regulatory liability on our consolidated statement of financial position for amounts we over collected in connection with the Southern Lights in-service delay. These amounts were not reflected in our revenues. Beginning in the second quarter 2012, we updated the transportation rates on our Lakehead system and began to reduce the transportation rates we charge the shippers to refund the excess amounts we collected.

FERC Transportation Tariffs

Effective April 1, 2012, we filed our annual tariff rate adjustment with the FERC to reflect true-ups for the difference between estimated and actual cost and throughput data for the prior year and our projected costs and throughput for 2012 related to our expansion projects. Also included was recovery of the costs related to the 2010 and 2011 Line 6B Integrity Program, including costs associated with the PHMSA Corrective Action Order as discussed in Note 9. Commitments and Contingencies—Pipeline Integrity Plan. The FSM, which was approved in July 2004, is a component of our Lakehead system’s overall rate structure and allows for the recovery of costs for enhancements or modifications to our Lakehead system.

 

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The tariff rate is applicable to each barrel of crude oil that is delivered on our system on or after the effective date of the tariff. This tariff filing decreased the average transportation rate for crude oil movements from the Canadian border to Chicago, Illinois by approximately $0.22 per barrel, to an average of approximately $1.60 per barrel.

On May 31, 2012, we filed FERC tariffs with effective dates of July 1, 2012 for our Lakehead, North Dakota and Ozark systems. We increased the rates in compliance with the indexed rate ceilings allowed by FERC which incorporates the multiplier of 1.086011, which was issued by FERC on May 15, 2012, in Docket No. RM93-11-000. The tariff filings are in part index filings in accordance with FERC filing 18 C.F.R.3423 and in part compliance filing with certain settlement agreements, which are not subject to FERC indexing. As an example, we increased the average transportation rate for crude oil movements on our Lakehead system from the Canadian border to Chicago, Illinois by approximately $0.07 per barrel, to an average of approximately $1.67 per barrel.

Effective July 1, 2011, we increased the rates for transportation on our Lakehead, North Dakota and Ozark systems in compliance with the indexed rate ceilings allowed by the FERC. In May 2011, the FERC determined that the annual change in the Producer Price Index for Finished Goods, or PPI-FG, plus 2.65% (PPI-FG + 2.65%) should be the oil pricing index for the five year period ending July 2016. The index is used to establish rate ceiling levels for oil pipeline rate changes. The increase in rates is due to an increase in the Producer Price Index for Finished Goods as compared with prior periods. For our Lakehead system, indexing applies only to the base rates and does not apply to the SEP II, Terrace and Facilities surcharges, which include the Southern Access and Alberta Clipper pipelines.

Effective December 19, 2011, we modified the terms of our transportation tariff on our Ozark system to implement a lottery process to allocate new shipper capacity if and when the number of new shippers nominating on the system precludes any individual new shipper from being allocated a minimum batch. Additionally, we increased the minimum accepted batch size from 10,000 Bpd to 30,000 Bpd to ensure accurate delivery measurement.

15. SUPPLEMENTAL CASH FLOWS INFORMATION

The following table provides supplemental information for the item labeled “Other” in the “Cash from operating activities” section our consolidated statements of cash flows.

 

     For the nine month
period ended September 30,
 
         2012             2011      
     (in millions)  

Amortization of debt issuance and hedging costs

   $ 9.6     $ 13.3  

Allowance for equity used during construction

     (5.6     —     

Write-down of project costs

     4.3       —     

Discount accretion

     0.5       0.5  

Deferred income taxes

     0.2       (0.9

Allowance for doubtful accounts

     —          0.6  

Gain on sale of CO2 plant

     —          (1.5

Other

     0.6       0.8  
  

 

 

   

 

 

 
   $ 9.6     $ 12.8  
  

 

 

   

 

 

 

 

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16. SUBSEQUENT EVENTS

Distribution to Partners

On October 31, 2012, the board of directors of Enbridge Management declared a distribution payable to our partners on November 14, 2012. The distribution will be paid to unitholders of record as of November 7, 2012, of our available cash of $198.5 million at September 30, 2012, or $0.5435 per limited partner unit. Of this distribution, $176.1 million will be paid in cash, $22.0 million will be distributed in i-units to our i-unitholder, Enbridge Management, and $0.4 million will be retained from our General Partner in respect of the i-unit distribution to maintain its 2% general partner interest.

Distribution to Series AC Interests

On October 31, 2012, the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and a holder of the Series AC interests, declared a distribution payable to the holders of the Series AC general and limited partner interests. The OLP will pay $12.9 million to the noncontrolling interest in the Series AC, while $6.5 million will be paid to us.

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

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

RESULTS OF OPERATIONS—OVERVIEW

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

 

   

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

 

   

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

 

   

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

We conduct our business through three business segments: Liquids, Natural Gas and Marketing. These segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.

 

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The following table reflects our operating income by business segment and corporate charges for each of the three and nine month periods ended September 30, 2012 and 2011.

 

     For the three month
period ended September 30,
    For the nine month
period ended September 30,
 
         2012             2011             2012             2011      
     (unaudited; in millions)  

Operating Income

        

Liquids

   $ 276.8     $ 148.4     $ 583.6     $ 518.8  

Natural Gas

     36.1       68.9       159.5       157.6  

Marketing

     (1.9     (1.2     (10.0     (0.4

Corporate, operating and administrative

     (0.5     (0.5     (1.4     (2.5
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Operating Income

     310.5       215.6       731.7       673.5  

Interest expense

     83.4       78.7       248.8       236.6  

Other income

     4.7       —          4.4       6.0  

Income tax expense

     2.6       2.1       6.4       5.3  
  

 

 

   

 

 

   

 

 

   

 

 

 

Net income

     229.2       134.8       480.9       437.6  

Less: Net income attributable to noncontrolling interest

     14.0       12.2       42.1       41.0  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

   $ 215.2     $ 122.6     $ 438.8     $ 396.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

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

Summary Analysis of Operating Results

Liquids

The following factors affected the operating income of our Liquids business for the three and nine month periods ended September 30, 2012, as compared with the same periods of 2011:

 

   

Increased unrealized, non-cash, mark-to-market net losses of $43.3 million and $35.8 million for the three and nine month periods ended September 30, 2012, respectively, as compared with the same periods in 2011 related to derivative financial instruments;

 

   

Decreased environmental expense of $191.0 million and $154.2 million for the three and nine month periods ended September 30, 2012, respectively, as compared with the same periods of 2011 primarily due to:

 

   

Decreased expenses related to the Line 6B crude oil release of $115.0 million and $130.0 million for the three and nine month periods ended September 30, 2012, respectively, as compared with the same periods of 2011;

 

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Increased insurance recoveries related to the Line 6B crude oil release of $85.0 million and $35.0 million for the three and nine month periods ended September 30, 2012, respectively, as compared with the same periods of 2011; and

 

   

Increased expenses of $10.5 million, for costs related to the Line 14 crude oil release that occurred on July 27, 2012, offset the overall decrease in environmental expense;

 

   

Increased operating and administrative expenses of $24.2 million and $57.9 million for the three and nine month periods ended September 30, 2012, respectively, as compared with the same periods of 2011, primarily due to additional workforce related costs, increased integrity expense and increased property tax expenses.

In addition, the following factors affected the operating income of our Liquids business for the nine month period ended September 30, 2012, as compared with the same period of 2011:

 

   

Increased average daily delivery volumes on all three of our systems resulting in $33.2 million of additional operating revenue for the nine month period ended September 30, 2012, as compared with the same period in 2011; and

 

   

Increased operating expenses related to $52.2 million of oil measurement adjustments that were settled with a shipper on our Lakehead crude oil pipeline system in the second quarter of 2011 that did not occur in 2012.

Natural Gas

The following factors affected the operating income of our Natural Gas business for the three and nine month periods ended September 30, 2012, as compared with the same periods of 2011:

 

   

Increased unrealized, non-cash, mark-to-market net losses of $39.4 million and $5.0 million for the three and nine month periods ended September 30, 2012, respectively, as compared with the same periods of 2011;

 

   

Increased keep-whole processing earnings on our natural gas systems of $10.6 million and $36.3 million, for the three and nine month periods ended September 30, 2012, as compared to the same periods in 2011;

 

   

Increased operating results of $7.2 million for the three and nine month periods ended September 30, 2012, related to measured volumes at one of our North Texas plants that were improperly included in the original allocation from July 2011 through June 2012;

 

   

Decreased gross margin due to the recent decline in natural gas and NGL prices;

 

   

Increased operating costs of $11.9 million and $54.8 million for the three and nine month periods ended September 30, 2012, respectively, as compared with the same periods in 2011 primarily due to:

 

   

Increased current quarter costs of $4.3 million for the write down of surplus materials associated with the deferred portions of the Haynesville expansion within our East Texas system;

 

   

Increased current year costs of $7.5 million for investigation costs related to accounting misstatements at our Trucking and NGL marketing subsidiary; and

 

   

Increased allocated expenses, additional workforce costs and operational costs related to the expansion of our systems;

 

   

Increased cost of $7.0 million, for the nine month period ended September 30, 2012, to reduce the cost basis of our natural gas inventory to net realizable value; and

 

   

Decreased depreciation expense of $9.3 million, for the nine month period ended September 30, 2012, primarily due to a revision in depreciation rates for the Anadarko, North Texas and East Texas systems.

 

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Marketing

Increased operating losses in our Marketing segment for the three and nine month periods ended September 30, 2012, compared to the same periods in 2011, were primarily due to unrealized, non-cash, mark-to-market net losses attributable to financial instruments used to hedge our storage and transportation positions. Additionally, operating losses for the nine month period ended September 30, 2012 were also due to relatively stable and low natural gas prices during 2012, as compared to 2011. This price environment led to limited opportunities to benefit from significant price differentials between market centers.

Derivative Transactions and Hedging Activities

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

 

   

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”

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 September 30,
    For the nine month
period ended September 30,
 
         2012             2011             2012             2011      
     (unaudited; in millions)  

Liquids segment

        

Non-qualified hedges

   $ (9.6   $ 33.7     $ 2.7     $ 38.5  

Natural Gas segment

        

Hedge ineffectiveness

     (3.9     (1.5     1.2       (0.1

Non-qualified hedges

     (20.0     17.0       9.8       16.1  

Marketing

        

Non-qualified hedges

     (0.7     1.6       (3.1     (0.1
  

 

 

   

 

 

   

 

 

   

 

 

 

Commodity derivative fair value net gains (losses)

     (34.2     50.8       10.6       54.4  

Corporate

        

Hedge ineffectiveness

     (0.1     (0.1     0.2       (0.1

Non-qualified interest rate hedges

     (0.2     (0.1     (0.4     (0.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Derivative fair value net gains (losses)

   $ (34.5   $ 50.6     $ 10.4     $ 53.9  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

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RESULTS OF OPERATIONS—BY SEGMENT

Liquids

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

 

      For the three month
period ended September 30,
    For the nine  month
period ended September 30,
 
         2012             2011             2012             2011      
     (unaudited; in millions)  

Operating Results

        

Operating revenues

   $ 329.0     $ 363.0     $ 1,013.9     $ 974.7  
  

 

 

   

 

 

   

 

 

   

 

 

 

Environmental costs, net of recoveries

     (134.9     56.1       (109.0     45.2  

Oil measurement adjustments

     (2.0     (2.8     (9.1     (61.5

Operating and administrative

     98.6       74.4       276.4       218.5  

Power

     38.0       37.7       116.6       107.2  

Depreciation and amortization

     52.5       49.2       155.4       146.5  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses

     52.2       214.6       430.3       455.9  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating Income

   $ 276.8     $ 148.4     $ 583.6     $ 518.8  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating Statistics

        

Lakehead system:

        

United States (1)

     1,378       1,338       1,427       1,313  

Province of Ontario (1)

     378       375       381       372  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Lakehead system deliveries (1)

     1,756       1,713       1,808       1,685  
  

 

 

   

 

 

   

 

 

   

 

 

 

Barrel miles (billions)

     118       114       363       334  
  

 

 

   

 

 

   

 

 

   

 

 

 

Average haul (miles)

     728       724       733       726  
  

 

 

   

 

 

   

 

 

   

 

 

 

Mid-Continent system deliveries (1)

     214       233       228       225  
  

 

 

   

 

 

   

 

 

   

 

 

 

North Dakota system:

        

Trunkline (1)

     202       203       213       182  

Gathering (1)

     4       3       3       4  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total North Dakota system deliveries (1)

     206       206       216       186  
  

 

 

   

 

 

   

 

 

   

 

 

 

Total Liquids Segment Delivery Volumes (1)

     2,176       2,152       2,252       2,096  
  

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Average barrels per day in thousands.

Three month period ended September 30, 2012 compared with three month period ended September 30, 2011

The operating revenue of our Liquids segment decreased for the three month period ended September 30, 2012 when compared with the same period in 2011 mostly due to a $43.3 million increase in unrealized, non-cash, mark-to-market net losses for the three month period ended September 30, 2012, related to derivative financial instruments as compared with the same period in 2011, due to changes in average forward prices of crude oil for the respective periods. We use forward contracts to hedge a portion of the crude oil we expect to receive from our customers as a pipeline loss allowance as part of the transportation of their crude oil. We subsequently sell this crude oil at market rates. We use derivative financial instruments which fix the sales price we will receive in the future for the sale of this crude oil. We elected not to designate these derivative financial instruments as cash flow hedges.

 

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Our operating revenue was positively impacted by the filing of tariffs to increase the rates for our Lakehead, North Dakota and Ozark systems with Federal Energy Regulatory Commission, or FERC, that became effective July 1, 2012. These rate increases resulted from application of the index allowed by FERC. This change in index comprises approximately $11.9 million of the increase in operating revenue for the quarter ended September 30, 2012 when compared to the same period in 2011. This increase was partially offset by regulatory adjustments, which had a corresponding reduction to our rates.

In addition, our operating revenue increased by $4.9 million during the three month period ended September 30, 2012 due to the collection of fees from our Cushing storage terminal facilities, with the majority of these incremental revenues coming from storage facilities which were placed into service during 2012.

Environmental costs, net of recoveries decreased $191.0 million for the three month period ended September 30, 2012 when compared with the same period in 2011, of which $200 million related to the Line 6B crude oil release. During the three month period ended September 30, 2012, we increased our total incident cost accrual by $25.0 million, compared to an increase of $140.0 million for the three month period ended September 31, 2011. In addition we recognized $85.0 million more in insurance recoveries in connection with the Line 6B crude oil release during the three month period ended September 30, 2012 compared to the same period in 2011. Additional environmental costs and insurance recoveries are discussed below under Operating Impact of Lines 6A and 6B Crude Oil Releases. Offsetting this decrease in environmental costs, net of recoveries was $10.5 million of environmental costs recognized related to Line 14 crude oil release of our Lakehead system near Grand Marsh, Wisconsin that occurred on July 27, 2012.

The operating and administrative expenses of our Liquids business increased $24.2 million for the three month period ended September 30, 2012 when compared with the same period in 2011 primarily due to increased property tax expenses of $7.2 million. Other contributing factors were an increase of our pipeline integrity expense of $5.6 million and additional workforce related costs associated with the operational, administrative, regulatory and compliance support necessary for our systems of $3.8 million.

The increase in depreciation expense of $3.3 million for the three month period ended September 30, 2012 is directly attributable to the additional assets we have placed in service since the same period in 2011.

Operating Impact of Lines 6A and 6B Crude Oil Releases

We continue to perform necessary remediation, restoration and monitoring of the areas affected by the crude oil release from Line 6B of our Lakehead system. With respect to the Line 6B incident, we expect to make payments for additional costs associated with submerged oil and sheen monitoring and recovery operations, including remediation and restoration of the area, containment management, air and groundwater monitoring, scientific studies and hydrodynamic modeling, along with legal, professional and regulatory costs through future periods. All the initiatives we are undertaking in the monitoring and restoration phase are intended to restore the crude oil release area to the satisfaction of the appropriate regulatory authorities. Primarily due to an estimate of extended oversight by regulators and additional legal costs associated with various lawsuits, we have revised our total cost estimate to $810 million for the Line 6B incident, before insurance recoveries, as of September 30, 2012, reflecting an increase of $25.0 million from our estimate at June 30, 2012. Our total cost estimate for the Line 6A crude oil release remains unchanged at approximately $48 million, before insurance recoveries and excluding additional fines and penalties. We continue to monitor this estimate to determine if our estimate should be updated. We have the potential of incurring additional costs in connection with these incidents including modified remediation requirements, other fines and penalties, as well as expenditures for litigation and settlement of claims. Our estimated costs for these incidents are based on currently available information and will be updated as considered necessary to incorporate material new information as it becomes available.

On July 2, 2012, we received a Notice of Probable Violation, or NOPV, from the PHMSA, related to the Line 6B crude oil release, which indicated a $3.7 million civil penalty that we paid during the third quarter of 2012. We have included the amount of the penalty in our total estimated cost for the Line 6B crude oil release. In addition, on July 10, 2012, the National Transportation Safety Board, or NTSB, discussed the results of its investigation into the Line 6B crude oil release and subsequently publicly posted its final report on July 26, 2012.

 

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On October 3, 2012, we received a letter from the Environmental Protection Agency, or EPA, regarding a proposed order, which we refer to as the Proposed Order, for potential incremental containment and active recovery of submerged oil. We are in discussions with the EPA regarding the agency’s intent with respect to certain elements of the Proposed Order and the appropriate scope of these activities. As such, we have not included significant additional costs related to this Proposed Order in our total cost estimate and it is impracticable to provide an estimate at this time.

The claims for the crude oil release for Lines 6B were covered by the insurance policy that expired on April 30, 2011, which had an aggregate limit of $650.0 million for pollution liability. We have exceeded the limits of coverage under this insurance policy. We are pursuing recovery of the costs associated with the Line 6A crude oil release from third parties; however, there can be no assurance that any such recovery will be obtained. Additionally, fines and penalties would not be covered under our existing insurance policy.

Enbridge’s current comprehensive insurance program, which became effective May 1, 2012 has a current liability aggregate limit of $660.0 million, including pollution liability, and will remain effective through April 30, 2013.

Nine month period ended September 30, 2012 compared with nine month period ended September 30, 2011

Our Liquids segment contributed $583.6 million of operating income during the nine month period ended September 30, 2012, representing a $64.8 million increase over the $518.8 million operating income for the same period in 2011. The components comprising the operating income of our Liquids business changed during the nine month period ended September 30, 2012, as compared with the same period in 2011, primarily for the reasons noted above in our three month analysis, in addition to the factors discussed below.

The operating revenue of our Liquids segment increased for the nine month period ended September 30, 2012 when compared with the same period in 2011, mostly due to higher average daily delivery volumes on our three systems when compared to the same period in 2011. The overall increase in average delivery volumes on our systems increased operating revenues by approximately $33.2 million for our Liquids segment. The total average daily deliveries from our liquid systems increased approximately 7%, to 2.252 million barrels per day, or Bpd, for the nine month period ended September 30, 2012 from 2.096 million Bpd for the same period in 2011. The increase in average deliveries on our liquids systems was primarily derived from increases of crude oil supplies from conventional sources as well as strong refinery utilization in the Petroleum Administration for Defense District II, or PADD II.

In addition, in the second quarter 2011, 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 experienced in prior years. We recorded $52.2 million to “Oil measurement adjustments”, which is a reduction to operating expenses, for the nine month period ended September 30, 2011. There were no such settlements in the same period in 2012.

Future Prospects Update for Liquids

The following discussion provides an update to the status of projects that we and Enbridge are currently developing.

Eastern Access Projects

In October 2011, we and Enbridge announced two projects that will provide increased access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States. One of the projects involves the expansion of the Partnership’s Line 5 light crude line between

 

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Superior, Wisconsin and Sarnia, Ontario by 50,000 Bpd. Complementing the Line 5 expansion, Enbridge plans to reverse a portion of its Line 9A in western Ontario to permit crude oil movements eastbound from Sarnia to as far as Westover, Ontario. The Line 5 expansion is targeted to be in service during the first quarter of 2013, and the Line 9A reversal is targeted to be in service in late 2013. The project will enable growing light crude production from the Bakken shale and from Alberta to meet refinery needs in Michigan, Ohio and Ontario. The project provides another much needed transportation outlet for light crude, mitigating the current discounting of supplies in this basin, while also providing more favorable supply costs to refiners currently dependent on crudes priced off of the Atlantic basin.

In May 2012, we and Enbridge announced further plans to expand access to Eastern markets. The projects to be pursued by the Partnership include 1) expansion of the Spearhead North pipeline between Flanagan, Illinois and the Terminal at Griffith, Indiana by adding horsepower to increase capacity from 130,000 Bpd to 235,000 Bpd, and an additional 330,000 barrel crude oil tank at Griffith; and 2) replacement of additional sections of the Partnership’s Line 6B in Indiana and Michigan to increase capacity from 240,000 Bpd to 500,000 Bpd. Portions of the existing 30-inch diameter pipeline will be replaced with 36-inch diameter pipe. Subject to customary regulatory approvals, these projects are expected to be placed in-service during 2013 and 2014.

These projects collectively referred to as the Eastern Access Projects, including the previously announced Line 5 expansion, will cost approximately $2.2 billion and will be undertaken on a cost-of-service basis with the toll surcharge absorbing 50% of any cost overruns over $1.85 billion during the Competitive Toll Settlement, or CTS, term. The Eastern Access Projects will be funded 60% by our General Partner and 40% by the Partnership. Before the end of 2012, the Partnership has the option to reduce its funding and associated economic interest in the projects by up to 15 percentage points down to 25%. Additionally, within one year of the in-service date, scheduled for early 2014, the Partnership will also have the option to increase its economic interest held at that time by up to 15 percentage points.

Border to Flanagan Expansion

In addition, we also announced in May 2012 further expansion of our mainline pipeline system which includes: 1) increasing capacity on the existing 36-inch diameter Alberta Clipper pipeline from 450,000 Bpd to 570,000 Bpd into the Superior, Wisconsin Terminal; and 2) expanding of the existing 42-inch diameter Southern Access pipeline between the Superior Terminal and the Flanagan Terminal near Pontiac, Illinois from 400,000 Bpd to 560,000 Bpd. These projects require only the addition of pumping horsepower and crude oil tanks at existing sites with no pipeline construction, at a cost of approximately $360 million. Subject to finalization of scope and regulatory and shipper approvals, the expansions will be undertaken on a full cost-of-service basis and are expected to be available for service in mid-2014. We continue discussions with the shippers on scope of the expansions, which could lead to an upward revision to capacity and cost. The Border to Flanagan Expansions will be funded entirely by the Partnership.

The Eastern Access Projects and Border to Flanagan expansions complement Enbridge’s strategic initiative of expanding access to new markets in North America for growing production from western Canada and the Bakken Formation.

Enbridge, the ultimate parent of our General Partner, also announced in May 2012 complementary Eastern Access and Mainline expansion projects which include: 1) construction of a 35-mile pipeline adjacent to Enbridge’s Toledo Pipeline, originating at the Partnership’s Line 6B in Michigan to serve refineries in Michigan and Ohio; 2) a reversal of Enbridge’s Line 9B from Westover, Ontario to Montreal, Quebec to serve refineries in Quebec; and 3) expansions to add horsepower on existing lines on the Enbridge Mainline system from western Canada to the U.S. border.

 

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Berthold Rail

In December 2011, we announced that we will be proceeding with the Berthold Rail Project, a $145 million investment that will provide an interim solution to shipper needs in the Bakken region. The project will expand capacity into the Berthold, North Dakota Terminal by 80,000 Bpd and includes the construction of a three unit-train loading facility, crude oil tankage and other terminal facilities adjacent to existing facilities. During September 2012, the first phase of terminaling facilities was completed, providing an additional capacity of 10,000 Bpd to the Berthold Terminal. The loading facility and crude oil tankage are expected to be placed into service during the first quarter of 2013.

Bakken Pipeline Expansion

In August 2010, we announced the Bakken Project, a joint crude oil pipeline expansion project with an affiliate of Enbridge in the Bakken and Three Forks formations located in the states of Montana and North Dakota and the Canadian provinces of Saskatchewan and Manitoba. The Bakken Project will follow our existing rights-of-way in the United States and those of Enbridge Income Fund Holdings in Canada to terminate and deliver to the Enbridge Mainline system’s terminal at Cromer, Manitoba, Canada. The United States portion of the Bakken Project will expand the United States portion of the Portal Pipeline, which was reversed in 2011 in order to flow oil from Berthold to the United States border and on to Steelman, Saskatchewan, by constructing two new pumping stations in Kenaston and Lignite, North Dakota, and replacing an 11-mile segment of the existing 12-inch diameter pipeline that runs from these two locations. The project also calls for an expansion at our existing terminal and station in Berthold, North Dakota. When completed, the Bakken Project will provide capacity of 145,000 Bpd. This project, with the North Dakota mainline, will result in a total takeaway capacity for this region of 355,000 Bpd. The United States portion of the Bakken Project will have an estimated cost of approximately $340 million. We commenced construction in July of 2011 with an expected in-service date in the first quarter of 2013. In February 2012, we and Enbridge Income Fund Holdings in Canada, announced a second open season for the Bakken Pipeline Expansion to allow shippers the option of securing future capacity once the expansion is completed. The open season resulted in additional term commitments to support the Bakken Project.

Bakken Access Program

In October 2011, we announced the Bakken Access Program, a series of projects totaling approximately $100 million, which represents an upstream expansion that will further complement our Bakken expansion, as discussed above. This expansion program will substantially enhance our gathering capabilities on the North Dakota system by 100,000 Bpd. This program is expected to be in service by early 2013, and it involves increasing pipeline capacities, constructing additional storage tanks and adding truck access facilities at multiple locations in western North Dakota.

Cushing Terminal Storage Expansion Project

In July 2012, engineering design commenced on three new tanks and associated infrastructure totaling 936,000 barrels of incremental shell capacity at our Cushing terminal. The three additional tanks will have an estimated cost of $39 million and are targeted to be in service by August 2013.

In January 2012, we began construction on four new tanks at our Cushing South Terminal with an approximate shell capacity of 1.2 million barrels. As of September 30, 2012 two of the four tanks were completed. The tanks will have an estimated cost of $33 million and are targeted to be in service by December 2012.

During late 2010, we began construction on nine new storage tanks at our Cushing terminal with an approximate shell capacity of 3.2 million barrels. As of September 30, 2012 we have spent approximately $60 million on this project with all nine of the tanks currently in service.

 

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Line 6B Replacement Program

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 $286.0 million. Our Line 6B pipeline runs from Griffith, Indiana through Michigan to the international border at the St. Clair River. The new segments of pipeline are targeted to be placed in service during 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered through our Facilities Surcharge Mechanism, or FSM, which is part of the system-wide rates of the Lakehead system. We have subsequently revised the scope of this project to increase the diameter of all pipe segments upstream of Stockbridge, Michigan at a cost of approximately $31.0 million, which will bring the total capital for this replacement program to an estimated cost of $317.0 million. The $31.0 million of additional costs will be recovered through the FSM.

Enbridge United States Gulf Coast Projects

A key strength of the Partnership is our relationship with Enbridge. In 2011, Enbridge announced two major United States Gulf Coast market access pipeline projects, which when completed will pull more volume through the Partnership’s pipeline, and may lead to further expansions of our Lakehead pipeline system.

Flanagan South Pipeline

Enbridge’s Flanagan South Pipeline project will transport more volumes into Cushing, Oklahoma and twin its existing Spearhead pipeline, which starts at the hub in Flanagan, Illinois and delivers volumes into the Cushing hub. Based on the results of a second open season held in the first quarter of 2012, the Flanagan South Pipeline will be upsized to a 36-inch diameter line with an initial annual capacity of 585,000 Bpd, and expandable to 800,000 Bpd. Subject to regulatory and other approvals, the pipeline is expected to be in service by mid-2014.

Seaway Crude Pipeline

In December 2011, Enbridge completed the acquisition of a 50% interest in the Seaway Crude Pipeline System, or Seaway, from ConocoPhillips. Seaway is a 670-mile pipeline that includes a 500-mile, 30-inch pipeline long-haul system from Freeport, Texas to Cushing, Oklahoma, as well as a Texas City Terminal and Distribution System which serves refineries in Houston and Texas City areas. Seaway also includes 6.8 million barrels of crude oil tankage on the Texas Gulf Coast and four marine import facilities at two locations. The remaining 50% interest in Seaway is owned by Enterprise Products Partners L.P., or Enterprise Products. Enbridge and Enterprise Products announced plans to reverse the direction of the 500-mile Seaway pipeline to enable it to transport oil from Cushing, Oklahoma to the United States Gulf Coast and the reversal is underway. The initial 150,000 Bpd of capacity on the reversed system went into service in May 2012. Following pump station additions and modifications, which are expected to be completed by the first quarter of 2013, capacity would increase to 400,000 Bpd assuming a mix of light and heavy grades of crude oil.

In March 2012, Enbridge and Enterprise Products announced that they secured sufficient capacity commitments from shippers to proceed with an expansion of the Seaway pipeline that will more than double its capacity to 850,000 Bpd by the middle of 2014. In addition, a proposed 85-mile pipeline is expected to be built from Enterprise Product’s ECHO crude oil terminal southeast of Houston to the Port Arthur/Beaumont, Texas refining center. The new pipeline will offer incremental capacity of 560,000 Bpd and is expected to be available in mid- 2014.

Other Matters

Line 6B Pipeline Integrity Plan

We completed on schedule all the work required by the Pipeline and Hazardous Materials Safety Administration, or PHMSA, that we agreed to perform as part of our restart of Line 6B in September 2010. Additionally, a new line was installed beneath the St. Clair River in March 2011 and tied into the existing

 

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pipeline during June 2011, and we announced plans for the pipeline replacement plan discussed under Line 6B Replacement Program above. Additional integrity expenditures, which could be significant, may be required after this initial remediation program. The total cost of these integrity measures is separate from the remediation, restoration and monitoring costs 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. We expect to incur ongoing operating costs for pipeline integrity measures to ensure both regulatory compliance and to maintain the overall integrity of our pipeline systems.

We included in the supplement to our FSM, which was effective April 1, 2011, recovery of $175 million of capital costs and $5 million of operating costs for the 2010 and 2011 Line 6B Pipeline Integrity Plan. The costs associated with the Line 6B Pipeline Integrity Plan, 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.

Line 14 Corrective Action Orders

After the July 27, 2012 release of crude oil on Line 14, the PHMSA issued a Corrective Action Order on July 30, 2012 and an amended Corrective Action Order on August 1, 2012, which we refer to as the PHMSA Corrective Action Orders. The PHMSA Corrective Action Orders require us to take certain corrective actions, some of which have already been completed and some are still ongoing, as part of an overall plan for our Lakehead system.

A notable part of the PHMSA Corrective Action Orders was to hire an independent third party pipeline expert to review and assess our overall integrity program. The third party assessment would include organizational issues, response plans, training and systems. An independent third party pipeline expert was contracted during the third quarter of 2012 and their work is currently ongoing. The total cost of this plan is separate from the repair and remediation costs as discussed in Note 9. Commitments and Contingencies—Lakehead Line 14 Crude Oil Release and is not expected to have a material impact on future results of operations.

Upon restart of Line 14 on August 7, 2012, PHMSA restricted the operating pressure to 80% of the pressure in place at the time immediately prior to the incident. The pressure restrictions will remain in place until such time we can demonstrate that the root cause of the incident has been remediated.

 

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Natural Gas

The following tables set forth the operating results of our Natural Gas segment assets and approximate average daily volumes of our major systems in millions of British Thermal Units, or MMBtu/d, for the periods presented.

 

     For the three month
period ended September 30,
     For the nine month
period ended September 30,
 
     2012      2011      2012      2011  
     (unaudited; in millions)  

Operating revenues

   $ 864.3      $ 1,436.4      $ 2,940.0      $ 4,384.2  
  

 

 

    

 

 

    

 

 

    

 

 

 

Cost of natural gas

     677.5        1,233.3        2,334.8        3,826.8  

Environmental costs, net of recoveries

     —           —           —           (0.4

Operating and administrative

     116.4        104.5        344.6        289.8  

Depreciation and amortization

     34.3        29.7        101.1        110.4  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating expenses

     828.2        1,367.5        2,780.5        4,226.6  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating Income

   $ 36.1      $ 68.9      $ 159.5      $ 157.6  
  

 

 

    

 

 

    

 

 

    

 

 

 

Operating Statistics (MMBtu/d)

           

East Texas

     1,219,000        1,469,000        1,276,000        1,392,000  

Anadarko

     1,065,000        1,039,000        1,023,000        1,007,000  

North Texas

     343,000        333,000        330,000        340,000  
  

 

 

    

 

 

    

 

 

    

 

 

 

Total

     2,627,000        2,841,000        2,629,000        2,739,000  
  

 

 

    

 

 

    

 

 

    

 

 

 

Three month period ended September 30, 2012 compared with three month period ended September 30, 2011

The primary factors affecting the operating income of our Natural Gas business for the three month period ended September 30, 2012 as compared with the same period of 2011 are as follows:

 

   

$39.4 million increase in unrealized, non-cash, mark-to-market net losses from derivative instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance, as compared with the same period of 2011;

 

   

$10.6 million increase in keep-whole processing earnings on our natural gas systems;

 

   

$7.2 million increase in operating results related to measured volumes at one of our North Texas plants that were improperly included in the original allocations from July 2011 through June 2012;

 

   

Decreased gross margin due to the recent decline in natural gas and NGL prices;

 

   

$11.9 million increase in operating and administrative costs primarily associated with writing down $4.3 million of surplus materials associated with the deferred portions of the Haynesville expansion within our East Texas system. The additional increases to operating and administrative costs were associated with increases in allocated expenses, additional workforce costs and operational costs related to the expansion of our systems; and

 

   

$4.6 million increase in depreciation associated with additional assets that were put in service during 2011.

Changes in the average forward prices of natural gas, NGLs and condensate from June 30, 2012 to September 30, 2012 produced unrealized, non-cash, mark-to-market net losses of $23.9 million, compared to net gains of $15.5 million for the same period in 2011, from the non-qualifying commodity derivatives we use to economically hedge a portion of the natural gas, NGLs and condensate resulting from the operating activities of our Natural Gas business. The average forward and daily prices for natural gas and NGLs increased for the three month period ended September 30, 2012, compared to a decrease during the same period of 2011. As a result of

 

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these increases to forward and daily prices, we experienced unrealized, non-cash, mark-to-market net losses during the third quarter of 2012.

The following table depicts the effect that unrealized, non-cash, mark-to-market net gains and losses had on the operating results of our Natural Gas segment for the three and nine month periods ended September 30, 2012 and 2011:

 

     For the three  month
period ended September 30,
    For the nine month
period ended September 30,
 
         2012             2011             2012              2011      
     (unaudited; in millions)  

Hedge ineffectiveness

   $ (3.9   $ (1.5   $ 1.2      $ (0.1

Non-qualified hedges

     (20.0     17.0       9.8        16.1  
  

 

 

   

 

 

   

 

 

    

 

 

 

Derivative fair value gains (losses)

   $ (23.9   $ 15.5     $ 11.0      $ 16.0  
  

 

 

   

 

 

   

 

 

    

 

 

 

Revenue for our Natural Gas business is derived from the fees or commodities we receive from the gathering, transportation, processing and treating of natural gas and NGLs for our customers. We are exposed to fluctuations in commodity prices in the near term on approximately 30% to 40% of the natural gas, NGLs and condensate we expect to receive as compensation for our services. As a result of this unhedged commodity price exposure, our gross margin, representing revenue less cost of natural gas, generally increases when the prices of these commodities are rising and generally decreases when the prices are declining. For the three month period ended September 30, 2012, prices for natural gas and NGLs declined significantly when compared to prices for the same period in 2011. Changing industry fundamentals have resulted in significant downward pressure in current and forward NGL prices, specifically in ethane and propane. We expect the near term outlook for our natural gas segment will be negatively impacted by this recent decline in NGL prices, resulting in a reduction to our 2012 gross margin and the overall earnings of the Partnership.

A variable element of the operating results of our Natural Gas segment is derived from processing natural gas on our systems. Under percentage of liquids, or POL, contracts, we are required to pay producers a contractually fixed recovery of NGLs regardless of the NGLs we physically produce or our ability to process the NGLs from the natural gas stream. NGLs that are produced in excess of this contractual obligation in addition to the barrels that we produce under traditional keep-whole gas processing arrangements we refer to collectively as keep-whole earnings. Operating revenue less the cost of natural gas derived from keep-whole earnings for the three month period ended September 30, 2012 was $22.6 million, representing an increase of $10.6 million from the $12.0 million we produced for the same period in 2011.

During the third quarter of 2012, it was discovered that measured volumes at one of our North Texas plants were being improperly included as part of the NGL revenue allocation with third party producers. The volumes of NGLs being measured had not been properly adjusted in the accounting allocation for our condensate stabilizer that was placed into service during June 2011. Due to this situation, for the period from July 2011 through June 2012, we understated a total of approximately $7.2 million of operating revenues on our North Texas system, $2.8 million of which related to 2011. During the quarter ended September 30, 2012, we recognized $7.2 million of additional revenues for these allocation corrections.

Operating and administrative costs of our Natural Gas segment for the three month period ended September 30, 2012 were negatively impacted by a $4.3 million adjustment to write down project line pipe to net realizable value, as well as, expense development, engineering and other costs associated with a project in East Texas. Due to lower levels of producer activity in the East Texas region, this project was deferred to a later date and it was determined that these costs and line pipe have no future benefit. As such, these costs were expensed and the line pipe written down for the period ended September 30, 2012. There were no similar adjustments for the same period in 2011.

 

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Additional increases to operating and administrative costs were due to increases in allocated expenses associated with the expansion of our systems. Our General Partner charges us the costs associated with employees and related benefits for personnel that are assigned to us or otherwise provide us with managerial and administrative services. Also contributing to the increases were additional workforce costs and operational related costs also associated with the expansion of our systems.

The increase in depreciation expense of $4.6 million for the three month period ended September 30, 2012 is directly attributable to the additional assets we have placed in service since the same period in 2011.

Nine month period ended September 30, 2012 compared with nine month period ended September 30, 2011

The primary factors affecting the operating income of our Natural Gas business for the nine month period ended September 30, 2012, as compared with the same period of 2011, are the same as noted in our three month analysis in addition to the factors discussed below.

During the first quarter of 2012, Anadarko capacity was negatively impacted when a third-party facility shut down due to an incident. The results from our natural gas business were unfavorably impacted by approximately $6.6 million due to the downtime at a third-party fractionation facility which resulted in production from our Anadarko system being shut-in for approximately two weeks.

For the three month period ended March 31, 2011, our volumes were negatively impacted due to uncharacteristically cold weather and freezing precipitation in February 2011 that moved through Oklahoma and north Texas with temperatures dropping below freezing for extended periods. These conditions resulted in mechanical issues with our producers’ equipment and impacted their ability to flow natural gas. Producers shut in significant volumes during this period, which reduced the average daily volumes on our systems by approximately 56,000 MMBtu/d. Additionally, mechanical problems on two of our plants required that they be taken out of service for extended periods during the first quarter of 2011 to correct these conditions. The adverse weather conditions and plant downtime had an approximate $13 million negative impact to the gross margin of our Natural Gas business for the nine month period ended September 30, 2011.

Operating and administrative costs of our Natural Gas segment for the nine month period ended September 30, 2012 were negatively impacted by $7.5 million in investigation costs related to accounting misstatements at our Trucking and NGL marketing subsidiary with no similar costs during the same period in 2011.

Operating income for the nine month period ended September 30, 2012 was also negatively affected by non-cash charges to inventory of $7.8 million, which we recorded to reduce the cost basis of our NGL and crude oil inventories to net realizable value. Similar charges of $0.8 million were recorded for the comparable period of 2011.

Depreciation expense for the nine month period ended September 30, 2012 decreased $9.3 million, as compared with the same period of 2011, primarily due to a revision in depreciation rates for the Anadarko, North Texas and East Texas systems which became effective on July 1, 2011. The revision resulted in a decrease of approximately $17 million in depreciation expense for the nine month period ended September 30, 2012, when compared to the same period of 2011. This decrease was offset with an increase in depreciation expense associated with additional assets that were put in service during 2011.

Future Prospects for Natural Gas

The following discussion provides an update to the status of projects that we and Enbridge are currently developing.

 

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Texas Express Pipeline

In September 2011, we announced a joint venture among us, Enterprise Products, and Anadarko Petroleum Corporation, or Anadarko, to design and construct a new NGL pipeline and two new NGL gathering systems, collectively referred to as the Texas Express Pipeline project, or TEP. In April 2012, DCP Midstream LLC, or DCP, announced plans to purchase a 10% ownership in the NGL pipeline portion of TEP from Enterprise Products. After DCP’s purchase, the NGL pipeline portion of TEP is owned 35% by Enterprise Products, our ownership continues to be 35%, 20% by Anadarko and 10% by DCP, while the ownership in two new NGL gathering systems will be owned 45% by Enterprise Products, 35% by us and 20% by Anadarko. Our portion of the total estimated cost is $385 million. The pipeline will originate at Skellytown, Texas and extend approximately 580-miles to NGL fractionation and storage facilities in Mont Belvieu, Texas. The pipeline will have an initial capacity of approximately 280,000 Bpd and will be readily expandable to approximately 400,000 Bpd. Approximately 250,000 Bpd of capacity has been subscribed on the pipeline.

In addition, the TEP joint venture project will include two new NGL gathering systems. The first will connect TEP NGL pipeline to natural gas processing plants in the Anadarko/Granite Wash production area located in the Texas Panhandle and Western Oklahoma. The second NGL gathering system will connect the new pipeline to central Texas, Barnett Shale processing plants. Volumes from the Rockies, Permian Basin and Mid-Continent regions will be delivered to the TEP system utilizing Enterprise’s existing Mid-America Pipeline assets between the Conway hub and Enterprise’s Hobbs NGL fractionation facility in Gaines County, Texas. In addition, volumes from and to the Denver-Julesburg Basin in Weld County, Colorado will be able to access TEP through the connecting Front Range Pipeline as proposed by Enterprise Products, DCP and Anadarko. Enterprise Products will construct and serve as the operator of the pipeline, while we will build and operate the new gathering systems. The pipeline and portions of the gathering systems are expected to begin service in mid-2013, subject to regulatory approvals and finalization of commercial agreements.

TEP will serve as a link between growing supply sources of NGLs in the Anadarko region and the primary end use market on the United States Gulf Coast and will provide guaranteed NGL access to the primary United States petrochemical market located in Mont Belvieu. TEP will assist us in fulfilling our strategic objective of expanding our presence in the natural gas and NGL value chain and provide us with a new source of strong and stable cash flow.

Ajax Cryogenic Processing Plant

In August 2011, we announced plans to construct an additional processing plant and other facilities, including compression and gathering infrastructure, on our Anadarko system at a cost of $230 million, which we refer to as our Ajax Plant. The Ajax Plant has a planned capacity of 150 million cubic feet per day, or MMcf/d, and is intended to meet the continued strength of horizontal drilling activity in this area. The Ajax Plant is anticipated to be in service in mid-2013.

The Ajax plant, when operational, in addition to the Allison Plant, will increase the total processing capacity on our Anadarko system to approximately 1,200 MMcf/d.

South Haynesville Shale Expansion

In February 2010, we announced plans to expand our East Texas system by constructing three lateral pipelines into the East Texas portion of the Haynesville shale, together with a large diameter lateral pipeline from Shelby County to Carthage which will further expand our recently completed Shelby County Loop. The expansion into the Haynesville shale area increased the capacity of our East Texas system by 900 MMcf/d. We completed construction of a portion of the pipeline for the project during the second quarter of 2010 and the main trunkline to Carthage in December 2010. Construction of the facilities was completed in the second quarter of 2012.

 

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In April 2011, we announced plans to invest an additional $175 million to expand our East Texas system. We have signed long-term agreements with four major natural gas producers along the Texas side of the Haynesville shale to provide gathering, treating and transmission services in Shelby, San Augustine and Nacogdoches counties. The projects involve construction of gathering and related market outlet pipelines and related treating facilities in the Texas Haynesville shale. Due to lower levels of producer activity, in light of weak natural gas prices, the Partnership has deferred portions of its Haynesville natural gas expansion pending increases in drilling activity.

Marketing

The following table sets forth the operating results of our Marketing segment assets for the periods presented:

 

     For the three  month
period ended September 30,
    For the nine  month
period ended September 30,
 
         2012             2011             2012             2011      
     (unaudited; in millions)  

Operating revenues

   $ 371.0     $ 572.8     $ 981.0     $ 1,674.2  
  

 

 

   

 

 

   

 

 

   

 

 

 

Cost of natural gas

     371.1       572.1       985.9       1,669.4  

Operating and administrative

     1.8       1.9       5.1       5.2  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating expenses

     372.9       574.0       991.0       1,674.6  
  

 

 

   

 

 

   

 

 

   

 

 

 

Operating loss

   $ (1.9   $ (1.2   $ (10.0   $ (0.4
  

 

 

   

 

 

   

 

 

   

 

 

 

Our Marketing business derives a majority of its operating income from selling natural gas received from producers on our Natural Gas segment pipeline assets to customers utilizing the natural gas. A majority of the natural gas we purchase is produced in Texas, where we have expanded our access to several interstate natural gas pipelines over the past several years, which we use to transport natural gas to market hubs to be sold.

Three month period ended September 30, 2012 compared with three month period ended September 30, 2011

The operating results of our Marketing segment for the three month period ended September 30, 2012 decreased by $0.7 million when compared to the same period in 2011.

Included in the operating results of our Marketing segment for the three month period ended September 30, 2012 were unrealized, non-cash, mark-to-market net losses of $0.7 million as compared with $1.6 million of unrealized non-cash, mark-to-market net gains for the same period in 2011 associated with derivative instruments that do not qualify for hedge accounting treatment under authoritative accounting guidance. This increase in unrealized, non-cash, mark-to-market net losses for the three month period ended September 30, 2012, as compared to the same period in 2011, was primarily attributed to the realization of financial instruments used to hedge our storage and transportation positions.

Offsetting the derivative activity; for the three month period ended September 30, 2011, we recorded $1.2 million of non-cash charges to inventory to reduce the cost basis of our natural gas inventory to net realizable value. Similar charges were not recorded for the three month period ended September 30, 2012.

Nine month period ended September 30, 2012 compared with nine month period ended September 30, 2011

The components comprising our operating results changed during the nine month period ended September 30, 2012, compared to the same period in 2011, for the same reasons as in the three month analysis, in addition to the items noted below.

 

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Natural gas prices during 2012 were relatively stable and low as compared to the same period of 2011. This price environment led to limited opportunities to benefit from significant price differentials between market centers, which negatively impacted the Marketing segment operating results by $5.9 million for the nine month period ended September 30, 2012, as compared to the same period in 2011.

Operating results for the nine month period ended September 30, 2012 were also negatively affected by non-cash charges to inventory of $2.0 million, which we recorded to reduce the cost basis of our natural gas inventory to net realizable value. Similar charges of $1.2 million were recorded in the comparable period of 2011. Since we hedge our storage positions financially, these charges will be recovered when the physical natural gas inventory is sold or as the financial hedges are realized.

Corporate

Our interest cost for the three and nine month periods ended September 30, 2012 and 2011 is comprised of the following:

 

     For the three  month
period ended September 30,
    For the nine month
period ended September 30,
 
         2012             2011             2012             2011      
     (unaudited; in millions)  

Interest expense

   $ 83.4     $ 78.7     $ 248.8     $ 236.6  

Interest capitalized

     7.3       3.8       22.0       7.5  
  

 

 

   

 

 

   

 

 

   

 

 

 

Interest cost incurred

   $ 90.7     $ 82.5     $ 270.8     $ 244.1  
  

 

 

   

 

 

   

 

 

   

 

 

 

Weighted average interest rate

     6.3     6.3     6.4     6.4

Three month period ended September 30, 2012 compared with three month period ended September 30, 2011

The increase in interest expense between the three month periods ended September 30, 2012 and 2011 is primarily the result of a higher weighted average outstanding debt balance during the three month period ended September 30, 2012, as compared with the same period in 2011. The increased weighted average outstanding debt balance was primarily a result of the issuance and sale in September 2011 of $600 million of our 4.20% senior unsecured notes due 2021 and an additional $150 million of our 5.50% senior unsecured notes due 2040.

Nine month period ended September 30, 2012 compared with nine month period ended September 30, 2011

The results for corporate activities for the nine month period ended September 30, 2012, compared to the same period in 2011, changed for the same reasons as noted in the three-month analysis above, partially offset by a lower commercial paper balance.

Other Matters

Alberta Clipper Pipeline Joint Funding Arrangement and Regulatory Accounting

In July 2009, we entered into a joint funding arrangement to finance construction of the United States segment of the Alberta Clipper Pipeline with several of our affiliates and affiliates of Enbridge, including our General Partner. The Alberta Clipper Pipeline was mechanically complete in March 2010 and was ready for service on April 1, 2010. In connection with the joint funding arrangement, we allocated earnings derived from operating the Alberta Clipper Pipeline in the amount of $14.0 million and $42.1 million to our General Partner for its 66.67% share of the earnings of the Alberta Clipper Pipeline for the three and nine month periods ended September 30, 2012. We allocated $12.2 million and $41.0 million for the same three and nine month periods

 

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ended September 30, 2011. 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.

Proceeds from Claim Settlements

In April 2011, 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 statement of income for the nine month period ended September 30, 2011.

LIQUIDITY AND CAPITAL RESOURCES

Available Liquidity

As set forth in the following table, we had approximately $2.1 billion of liquidity available to us at September 30, 2012 to meet our ongoing operational, investment and financing needs, as well as the funding requirements associated with the environmental costs resulting from the crude oil releases on Lines 6A and 6B.

 

     (unaudited; in millions)  

Cash and cash equivalents

   $ 233.5  

Total credit available under Credit Facilities (1)

     2,675.0  

Less: Amounts outstanding under Credit Facilities (1)

     —     

Principal amount of commercial paper issuances

     560.0  

Letters of credit outstanding

     226.4  
  

 

 

 

Total

   $ 2,122.1  
  

 

 

 

 

(1) 

We refer to our credit agreement that we entered into in September 2011 and our 364-Day Credit Facility that we entered into on July 6, 2012 as our Credit Facilities.

General

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

Our current business strategy emphasizes developing and expanding our existing Liquids and Natural Gas businesses through organic growth and targeted acquisitions. We expect to initially fund our long-term cash requirements for expansion projects and acquisitions, as well as, retire our maturing and callable debt, first from operating cash flows and then from issuances of commercial paper and borrowings on our Credit Facilities. Likewise, we anticipate initially retiring our maturing debt with similar borrowings on our Credit Facilities. We expect to obtain permanent financing as needed through the issuance of additional equity and debt securities, which we will use to repay amounts initially drawn to fund these activities, although there can be no assurance that such financings will be available on favorable terms, if at all.

As of September 30, 2012, we had a working capital deficit of approximately $576.8 million and over $2.1 billion of liquidity to meet our ongoing operational, investing and finance needs as of September 30, 2012 as shown above, as well as the funding requirements associated with the environmental costs resulting from the crude oil releases on Lines 6A and 6B.

 

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Capital Resources

Equity and Debt Securities

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

Issuance of Class A Common Units

The following table presents the net proceeds from our Class A common unit issuances for the current year. The proceeds from the September 2012 offering will be used to fund a portion of our capital expansion projects, for general partnership purposes or any combination of such purposes.

 

2012 Issuance Date

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

September

     16,100,000      $ 28.64      $ 446.8      $   9.4   $   456.2

 

(1) 

Net of underwriters’ fees and discounts, commissions and issuance expenses.

(2) 

Contributions made by the General Partner to maintain its 2% general partner interest.

Available Credit

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

Credit Facilities

In September 2011, we entered into a credit agreement with Bank of America, as administrative agent, and the lenders party thereto, which we refer to as the Credit Facility. The agreement is a committed senior unsecured revolving credit facility that permits aggregate borrowings of up to, at any one time outstanding, $2 billion, a letter of credit subfacility and a swing line subfacility. Effective September 26, 2012, we extended the maturity date to September 26, 2017 and amended it to adjust the base interest rates.

On July 6, 2012, we entered into a credit agreement with JPMorgan Chase Bank, as administrative agent, and a syndicate of 12 lenders, which we refer to as the 364-Day Credit Facility. The agreement is a committed senior unsecured revolving credit facility pursuant to which the lenders have committed to lend us up to $675 million 1) on a revolving basis for a 364-day period, extendible annually at the lenders’ discretion; and 2) for a 364-day term on a non-revolving basis following the expiration of all revolving periods. We refer to the 364-Day Credit Facility and the Credit Facility as our Credit Facilities.

 

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The amounts we may borrow under the terms of our Credit Facilities are reduced by the face amount of our letters of credit outstanding. It is our policy to maintain availability at any time under our Credit Facilities amounts that are at least equal to the amount of commercial paper that we have outstanding at such time. Taking that policy into account, at September 30, 2012, we could borrow $1,888.6 million under the terms of our Credit Facilities, determined as follows:

 

     (in millions)  

Total credit available under Credit Facilities

   $ 2,675.0  

Less: Amounts outstanding under Credit Facilities

     —     

Principal amount of commercial paper outstanding

     560.0  

Letters of credit outstanding

     226.4  
  

 

 

 

Total amount we could borrow at September 30, 2012

   $ 1,888.6  
  

 

 

 

Individual London Inter-Bank Offered Rate, or LIBOR rate, borrowings under the terms of our Credit Facilities may be renewed as LIBOR rate borrowings or as base rate borrowings at the end of each LIBOR rate interest period, which is typically a period of three months or less. These renewals do not constitute new borrowings under the Credit Facilities and do not require any cash repayments or prepayments. For the three and nine month periods ended September 30, 2012 and 2011, we have not renewed any LIBOR rate borrowings or base rate borrowings, on a non-cash basis.

Effective September 30, 2011, our Credit Facility was amended to modify the definition of Consolidated Earnings Before Income Taxes Depreciation and Amortization, or Consolidated EBITDA, as set forth in the terms of our Credit Facility, to increase from $550 million to $650 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 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 September 30, 2012, we were in compliance with the terms of our financial covenants.

Commercial Paper

At September 30, 2012, we had $560.0 million of commercial paper outstanding at a weighted average interest rate of 0.48%, excluding the effect of our interest rate hedging activities. Under our commercial paper program, we had net borrowings of approximately $285.0 million during the nine month period ended September 30, 2012, which include gross borrowings of $6,097.7 million and gross repayments of $5,812.7 million. Our policy is that the commercial paper we can issue is limited by the amounts available under our Credit Facilities up to an aggregate principal amount of $1.5 billion.

Joint Funding Arrangement for Alberta Clipper Pipeline

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

In March 2010, we refinanced $324.6 million of amounts we had outstanding and payable to our General Partner under the A1 Credit Agreement by issuing a promissory note payable to our General Partner, which we refer to as the A1 Term Note. At such time we also terminated the A1 Credit Agreement. The A1 Term Note matures on March 15, 2020, bears interest at a fixed rate of 5.20% and has a maximum loan amount of $400 million. The terms of the A1 Term Note are similar to the terms of our 5.20% senior notes due 2020, except that the A1 Term Note has recourse only to the assets of the United States portion of the Alberta Clipper Pipeline. Under the terms of the A1 Term Note, we have the ability to increase the principal amount outstanding to finance the debt portion of the investment our General Partner is obligated to make pursuant to the Alberta Clipper Joint

 

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Funding Arrangement to finance any additional costs associated with the construction of our portion of the Alberta Clipper Pipeline we incur after the date the original A1 Term Note was issued. The increases we make to the principal balance of the A1 Term Note will also mature on March 15, 2020. At September 30, 2012, we had approximately $330.0 million outstanding under the A1 Term Note.

Our General Partner also made equity contributions totaling $3.3 million to the OLP during the nine month period ended September 30, 2011 to fund its equity portion of the construction costs associated with the Alberta Clipper Pipeline. No such contributions were made during the nine month period ended September 30, 2012. The OLP paid a distribution of $47.0 million to our General Partner and its affiliate during the nine month period ended September 30, 2012 for their noncontrolling interest in the Series AC, representing limited partner ownership interests of the OLP that are specifically related to the assets, liabilities and operations of the Alberta Clipper Pipeline.

We allocated earnings derived from operating the Alberta Clipper Pipeline in the amount of $42.1 million to our General Partner for its 66.67% share of the earnings of the Alberta Clipper Pipeline for the nine month period ended September 30, 2012. We allocated $41.0 million for the same nine month period ended September 30, 2011. We have presented the amounts we allocated to our General Partner for its share of the earnings of the Alberta Clipper Pipeline in “Net income attributable to noncontrolling interest” on our consolidated statements of income.

Joint Funding Arrangement for Eastern Access Projects

In May 2012, we entered into a joint funding arrangement to finance projects to increase access to refineries in the United States Upper Midwest and in Ontario, Canada for light crude oil produced in western Canada and the United States, which we refer to as our Eastern Access Projects. The Eastern Access Projects will be funded 60% by our General Partner and 40% by the Partnership.

Our General Partner has made equity contributions totaling $122.3 million to the OLP during the nine month period ended September 30, 2012 to fund its equity portion of the construction costs associated with the Eastern Access Projects.

Cash Requirements

Capital Spending

We expect to make additional expenditures during the remainder of the year for the acquisition and construction of natural gas processing and crude oil transportation infrastructure. In 2012, we expect to spend approximately $2,015 million on system enhancements and other projects associated with our liquids and natural gas systems with the expectation of realizing additional cash flows as projects are completed and placed into service. We expect to receive funding of approximately $205 million from our General Partner based on our joint funding arrangement for the Eastern Access Projects. We made capital expenditures of $1,293.6 million for the nine month period ending September 30, 2012, inclusive of $81.7 million in contributions to the Texas Express Pipeline and $122.3 million of expenditures that were financed by contributions from our General Partner via the joint funding arrangement. At September 30, 2012, we had approximately $628.0 million in outstanding purchase commitments attributable to capital projects for the construction of assets that will be recorded as property, plant and equipment during 2012.

Acquisitions

We continue to assess ways to generate value for our unitholders, including reviewing opportunities that may lead to acquisitions or other strategic transactions, some of which may be material. We evaluate opportunities against operational, strategic and financial benchmarks before pursuing them. We expect to obtain

 

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the funds needed to make acquisitions through a combination of cash flows from operating activities, borrowings under our Credit Facilities and the issuance of additional debt and equity securities. All acquisitions are considered in the context of the practical financing constraints presented by the capital markets.

Forecasted Expenditures

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

We estimate our capital expenditures based upon our strategic operating and growth plans, which are also dependent upon our ability to produce or otherwise obtain the financing necessary to accomplish our growth objectives. Given sustained natural gas prices and weaker NGL prices for ethane and propane, our Natural Gas business will face challenges over our near-term planning horizon. As such, with our focus to exercise prudent financial management and optimize our capital, we plan to reduce capital investment into the natural gas business in the near term. We will continue to consider opportunities in the Natural Gas business that will elevate our long-term, fee-based profile or strengthen our existing assets.

The following table sets forth our estimates of capital expenditures we expect to make for system enhancement and core maintenance for the year ending December 31, 2012. Although we anticipate making these expenditures in 2012, these estimates may change due to factors beyond our control, including weather-related issues, construction timing, changes in supplier prices or poor economic conditions, which may adversely affect our ability to access the capital markets. Additionally, our estimates may also change as a result of decisions made at a later date to revise the scope of a project or undertake a particular capital program or an acquisition of assets. We made capital expenditures of $1,293.6 million for the nine month period ending September 30, 2012 which includes $88.0 million on core maintenance activities, $81.7 million in contributions to the Texas Express Pipeline and $122.3 million of expenditures that were financed by our General Partner via the joint funding agreement. For the full year ending December 31, 2012, we anticipate our capital expenditures to approximate the following:

 

     Total
Forecasted
Expenditures
 
     (in millions)  

Capital Projects

  

System Enhancements

   $ 405  

North Dakota Expansion Program

     325  

Liquids Integrity Program

     255  

Line 6B Replacement Program

     215  

Ajax Cryogenic Processing Plant

     190  

Eastern Access Projects

     340  

Core Maintenance Activities

     110  

Joint Venture Projects

  

Texas Express Pipeline

     175  
  

 

 

 
     2,015  

Less: Joint Funding by General Partner

     205  
  

 

 

 
   $ 1,810  
  

 

 

 

 

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

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

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 are targeted to be placed in service during 2013 in consultation with, and to minimize impact to, refiners and shippers served by Line 6B crude oil deliveries. These costs will be recovered through our FSM that is part of the system-wide rates of the Lakehead system. We have subsequently revised the scope of this project to increase the cost by approximately $31.0 million, which will bring the total capital for this replacement program to an estimated cost of $317.0 million. The $31.0 million of additional costs will also be recovered through the FSM.

Additional integrity expenditures, which could be significant, may be required after this initial remediation program. 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.

We included in the supplement to our FSM, to be effective April 1, 2011, recovery of $175 million of capital costs and $5 million of operating costs for the 2010 and 2011 Line 6B Pipeline Integrity Plan. The costs associated with the Line 6B Pipeline Integrity Plan, 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.

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

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

Environmental

Lines 6A and 6B Crude Oil Releases

During the nine month period ended September 30, 2012, our cash flows were adversely affected by the approximate $122.0 million we paid for the environmental remediation, restoration and cleanup activities, excluding insurance recoveries and fines and penalties, resulting from the crude oil releases that occurred in 2010 on Lines 6A and 6B of our Lakehead system.

 

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Lakehead Line 14 Crude Oil Release

On July 27, 2012, a release of crude oil was detected on Line 14 of our Lakehead system near Grand Marsh, Wisconsin. We have updated our disclosed estimate for repair and remediation related costs associated with this crude oil release to approximately $12.1 million, inclusive of approximately $1.6 million of lost revenue and excluding any fines and penalties. Despite the efforts we have made to ensure the reasonableness of our estimate, changes to the estimated amounts associated with this release are possible as more reliable information becomes available.

Derivative Activities

We use derivative financial instruments (i.e., futures, forwards, swaps, options and other financial instruments with similar characteristics) to manage the risks associated with market fluctuations in 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.

The following table provides summarized information about the timing and expected settlement amounts of

our outstanding commodity derivative financial instruments based upon the market values at September 30, 2012 for each of the indicated calendar years:

 

     Notional      2012     2013     2014     2015      2016      Total (4)  
     (in millions)  

Swaps

                 

Natural gas (1)

     87,326,941      $ 0.4     $ 7.7     $ 0.1     $ —         $ —         $ 8.2  

NGL (2)

     4,291,395        5.0       5.2       0.9       0.9        —           12.0  

Crude Oil (2)

     4,586,347        (1.0     (3.3     3.5       7.3        0.5        7.0  

Options

                 

Natural gas—puts purchased (1)

     1,642,500        —          1.1       —          —           —           1.1  

NGL—puts purchased (2)

     1,059,784        6.7       3.8       —          —           —           10.5  

Crude Oil —puts purchased (2)

     16,100        0.1       —          —          —           —           0.1  

Forward contracts

                 

Natural gas (1)

     39,030,955        0.3       0.7       0.5       0.4        0.1        2.0  

NGL (2)

     5,526,289        2.8       0.8       —          —           —           3.6  

Crude Oil (2)

     1,374,816        1.5       —          —          —           —           1.5  

Power (3)

     115,536        (0.2     (0.4     (0.8     —           —           (1.4
     

 

 

   

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

Totals

      $ 15.6     $ 15.6     $ 4.2     $ 8.6      $ 0.6      $ 44.6  
     

 

 

   

 

 

   

 

 

   

 

 

    

 

 

    

 

 

 

 

(1) 

Notional amounts for natural gas are recorded in MMBtu.

(2) 

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

(3) 

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

(4) 

Fair values exclude credit adjustments of approximately $0.9 million of losses at September 30, 2012.

The following table provides summarized information about the timing and estimated settlement amounts of

our outstanding interest rate derivatives calculated based on implied forward rates in the yield curve at September 30, 2012 for each of the indicated calendar years:

 

      Notional
Amount
     2012     2013     2014     2015     2016     Thereafter     Total  
     (in millions)  

Interest Rate Derivatives

                 

Interest Rate Swaps:

                 

Floating to Fixed

   $ 2,425.0      $ (6.0   $ (26.6   $ (8.9   $ (7.2   $ (5.9   $ (2.5   $ (57.1

Fixed to Floating

   $ 125.0        0.9       2.9       —          —          —          —          3.8  

Pre-issuance hedges

   $ 2,350.0        (157.7     (87.9     (52.6     —          2.2       —          (296.0
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 
        $(162.8   $ (111.6   $ (61.5   $ (7.2   $ (3.7   $ (2.5   $ (349.3
     

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

   

 

 

 

 

(1) 

Fair values are presented in millions of dollars and exclude credit adjustments of approximately $16.1 million of gains at September 30, 2012.

 

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Cash Flow Analysis

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

 

     For the nine month
    period ended September 30,    
    Variance
2012 vs. 2011

Increase (Decrease)
 
         2012             2011        
     (unaudited; in millions)  

Total cash provided by (used in):

      

Operating activities

   $ 708.3     $ 652.6     $ 55.7  

Investing activities

     (1,218.0     (660.8     (557.2

Financing activities

     320.3       307.0       13.3  
  

 

 

   

 

 

   

 

 

 

Net increase (decrease) in cash and cash equivalents

     (189.4     298.8       (488.2

Cash and cash equivalents at beginning of year

     422.9       144.9       278.0  
  

 

 

   

 

 

   

 

 

 

Cash and cash equivalents at end of period

   $ 233.5     $ 443.7     $ (210.2
  

 

 

   

 

 

   

 

 

 

Operating Activities

Net cash provided by our operating activities increased $55.7 million for the nine month period ended September 30, 2012 primarily due to:

 

   

Increase in net income of $43.3 million offset by non-cash items which primarily consisted of a $43.5 million decrease in our derivative fair value net gains and a $62.5 million decrease in environmental cost net of recoveries as compared with the same period in 2011;

 

   

Payment of $18.8 million to settle interest rate derivatives in 2011 that did not occur in 2012; and

 

   

Changes in our working capital accounts of $15.9 million as compared to the same period in 2011, which were affected by general timing differences in the collection on, and payment of our current and related party accounts. The changes in working capital accounts for the nine month period were also affected by $122.0 million of environmental cost paid associated with Lines 6A and 6B crude oil releases for the nine month period ended September 30, 2012 as compared with $196.5 million of environmental costs paid in the same period in 2011.

Investing Activities

Net cash used in our investing activities during the nine month period ended September 30, 2012 increased by $557.2 million, compared to the same period of 2011, primarily due to additions to property, plant and equipment in 2012 related to various enhancement projects. We also made cash contributions to our joint venture project, Texas Express Pipeline, of $81.7 million during the nine months ended September 30, 2012.

Financing Activities

Net cash provided by our financing activities increased $13.3 million for the nine month period ended September 30, 2012, compared to the same period in 2011, primarily due to:

 

   

Increase in net borrowings on our commercial paper of $794.8 million;

 

   

Decrease of $740.7 million related to issuance of senior notes in 2011 that did not occur in 2012;

 

   

Increase of $119.0 million in capital contributions from our General Partner and its affiliates for its ownership interest in Alberta Clipper Pipeline and Eastern Access Projects;

 

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Decrease of $101.4 million in net proceeds related to Class A common units, which included a $2.1 million decrease in contributions from the General Partner related to these issuances to maintain its 2% interest;

 

   

Increase of cash used of $71.6 million for distributions to our partners in 2012; and

 

   

A decrease in cash used of $14.1 million for distributions to our General Partner and its affiliate for its ownership interest in Alberta Clipper Pipeline.

SUBSEQUENT EVENTS

Distribution to Partners

On October 31, 2012, the board of directors of Enbridge Management declared a distribution payable to our partners on November 14, 2012. The distribution will be paid to unitholders of record as of November 7, 2012, of our available cash of $198.5 million at September 30, 2012, or $0.5435 per limited partner unit. Of this distribution, $176.1 million will be paid in cash, $22.0 million will be distributed in i-units to our i-unitholder, Enbridge Management, and $0.4 million will be retained from our General Partner in respect of the i-unit distribution to maintain its 2% general partner interest.

Distribution to Series AC Interests

On October 31, 2012, the board of directors of Enbridge Management, acting on behalf of Enbridge Pipelines (Lakehead) L.L.C., the managing general partner of the OLP and a holder of the Series AC interests, declared a distribution payable to the holders of the Series AC general and limited partner interests. The OLP will pay $12.9 million to the noncontrolling interest in the Series AC, while $6.5 million will be paid to us.

REGULATORY MATTERS

FERC Transportation Tariffs

Effective April 1, 2012, we filed our annual tariff rate adjustment with the FERC to reflect true-ups for the difference between estimated and actual cost and throughput data for the prior year and our projected costs and throughput for 2012 related to our expansion projects. Also included was recovery of the costs related to the 2010 and 2011 Line 6B Integrity Program, including costs associated with the PHMSA Corrective Action Order as discussed in Note 9. Commitments and Contingencies—Pipeline Integrity Plan. The FSM, which was approved in July 2004, is a component of our Lakehead system’s overall rate structure and allows for the recovery of costs for enhancements or modifications to our Lakehead system.

The tariff rate is applicable to each barrel of crude oil that is delivered on our system on or after the effective date of the tariff. This tariff filing decreased the average transportation rate for crude oil movements from the Canadian border to Chicago, Illinois by approximately $0.22 per barrel, to an average of approximately $1.60 per barrel.

On May 31, 2012, we filed FERC tariffs with effective dates of July 1, 2012 for our Lakehead, North Dakota and Ozark systems. We increased the rates in compliance with the indexed rate ceilings allowed by FERC which incorporates the multiplier of 1.086011, which was issued by FERC on May 15, 2012, in Docket No. RM93-11-000. The tariff filings are in part index filings in accordance with FERC filing 18 C.F.R.3423 and in part compliance filing with certain settlement agreements, which are not subject to FERC indexing. As an example, we increased the average transportation rate for crude oil movements on our Lakehead system from the Canadian border to Chicago, Illinois by approximately $0.07 per barrel, to an average of approximately $1.67 per barrel.

 

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Effective July 1, 2011, we increased the rates for transportation on our Lakehead, North Dakota and Ozark systems in compliance with the indexed rate ceilings allowed by the FERC. In May 2011, the FERC determined that the annual change in the Producer Price Index for Finished Goods, or PPI-FG, plus 2.65% (PPI-FG + 2.65%) should be the oil pricing index for the five year period ending July 2016. The index is used to establish rate ceiling levels for oil pipeline rate changes. The increase in rates is due to an increase in the Producer Price Index for Finished Goods as compared with prior periods. For our Lakehead system, indexing applies only to the base rates and does not apply to the SEP II, Terrace and Facilities surcharges, which include the Southern Access and Alberta Clipper pipelines.

Effective December 19, 2011, we modified the terms of our transportation tariff on our Ozark system to implement a lottery process to allocate new shipper capacity if and when the number of new shippers nominating on the system precludes any individual new shipper from being allocated a minimum batch. Additionally, we increased the minimum accepted batch size from 10,000 Bpd to 30,000 Bpd to ensure accurate delivery measurement.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

The following should be read in conjunction with the information presented in our Annual Report on Form 10-K for the year ended December 31, 2011, in addition to information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. There have been no material changes to that information other than as presented below.

Our net income and cash flows are subject to volatility stemming from changes in interest rates on our variable rate debt obligations and fluctuations in commodity prices of natural gas, NGLs, condensate and fractionation margins, which is the relative difference between the price we receive from NGL sales and the corresponding cost of natural gas purchases. Our interest rate risk exposure does not exist within any of our segments, but exists at the corporate level where our fixed and variable rate debt obligations are issued. 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 commodity prices and interest rates, as well as to reduce volatility to our cash flows. Based on our risk management policies, all of our derivative financial instruments are employed in connection with an underlying asset, liability and forecasted transaction and are not entered into with the objective of speculating on interest rates or commodity prices.

 

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Interest Rate Derivatives

The table below provides information about our derivative financial instruments that we use to hedge the interest payments on our variable rate debt obligations that are sensitive to changes in interest rates and to lock in the interest rate on anticipated issuances of debt in the future. For interest rate swaps, the table presents notional amounts, the rates charged on the underlying notional amounts and weighted average interest rates paid by expected maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contract. Weighted average variable rates are based on implied forward rates in the yield curve at September 30, 2012.

 

                    Fair Value (2) at  

Date of Maturity & Contract Type

  Accounting
Treatment
  Notional     Average Fixed Rate  (1)     September 30,
2012
    December 31,
2011
 
              (dollars in millions)        

Contracts maturing in 2013

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge     $800       3.24   $ (28.5   $ (42.2

Interest Rate Swaps—Pay Fixed

  Non-qualifying   $ 125       4.35   $ (3.5   $ (6.8

Interest Rate Swaps—Pay Float

  Non-qualifying   $ 125       4.75   $ 3.8     $ 7.5  

Contracts maturing in 2014

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 200       0.56   $ (0.6   $ 0.2  

Contracts maturing in 2015

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 300       2.43   $ (6.6   $ (4.7

Contracts maturing in 2017

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 500       2.21   $ (16.1   $ (5.8

Contracts maturing in 2018

         

Interest Rate Swaps—Pay Fixed

  Cash Flow Hedge   $ 500       2.08   $ (1.8   $ —     

Contracts settling prior to maturity

         

2012—Pre-issuance Hedges

  Cash Flow Hedge   $ 600       4.56   $ (157.7   $ (123.7

2013—Pre-issuance Hedges

  Cash Flow Hedge   $ 500       3.98   $ (87.9   $ (63.1

2014—Pre-issuance Hedges

  Cash Flow Hedge   $ 750       3.15   $ (52.6   $ (23.4

2016—Pre-issuance Hedges

  Cash Flow Hedge   $ 500       2.87   $ 2.2     $ —     

 

(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 September 30, 2012 and December 31, 2011, 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 $16.1 million of gains at September 30, 2012 and $19.4 million of gains at December 31, 2011.

 

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The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity based swaps and physical contracts at September 30, 2012 and December 31, 2011.

 

    At September 30, 2012     At December 31, 2011  
              Wtd. Average
Price (2)
    Fair Value (3)     Fair Value (3)  
    Commodity   Notional (1)     Receive     Pay     Asset     Liability     Asset     Liability  

Portion of contracts maturing in 2012

             

Swaps

               

Receive variable/pay fixed

  Natural Gas     859,638     $3.25       $ 4.49     $0.2       $ (1.3)      $—          $ (8.1
  NGL     108,000     $59.59       $ 56.98     $0.5       $ (0.2)      $0.4       $ —     
  Crude Oil     85,000     $92.75       $ 92.22     $—          $ —        $—          $ —     

Receive fixed/pay variable

  Natural Gas     1,193,244     $4.38       $ 3.33     $1.3       $ (0.1)      $7.1       $ —     
  NGL     1,028,360     $59.10       $ 54.51     $7.0       $ (2.3)      $6.3       $ (20.6
  Crude Oil     585,292     $90.25       $ 91.96     $1.8       $ (2.8)      $3.5       $ (15.6

Receive variable/pay variable

  Natural Gas     25,217,278     $3.19       $ 3.18     $0.8       $ (0.5)      $2.8       $ (0.8

Physical Contracts

               

Receive variable/pay fixed

  NGL     80,000     $57.85       $ 60.83     $—          $ (0.3)      $0.3       $ —     
  Crude Oil     73,000     $92.56       $ 96.21     $—          $ (0.3)      $0.2       $ (0.3

Receive fixed/pay variable

  NGL     294,999     $41.90       $ 41.89     $0.3       $ (0.3)      $0.3       $ (1.0
  Crude Oil     146,000     $95.76       $ 92.77     $0.4       $ —        $0.1       $ (0.6

Receive variable/pay variable

  Natural Gas     10,349,133     $3.22       $ 3.19     $0.3       $ —        $1.2       $ —     
  NGL     3,950,067     $45.37       $ 44.60     $5.9       $ (2.8)      $8.8       $ (3.8
  Crude Oil     1,154,616     $93.41       $ 92.19     $4.1       $ (2.7)      $1.5       $ (1.9

Pay fixed

  Power (4)     14,004     $29.71       $ 40.23     $—          $ (0.2)      $—          $ (0.5

Portion of contracts maturing in 2013

             

Swaps

               

Receive variable/pay fixed

  Natural Gas     1,810,211     $3.71       $ 3.42     $0.7       $ (0.1)      $—          $ (0.1
  NGL     90,000     $84.07       $ 73.79     $0.9       $ —        $—          $ —     

Receive fixed/pay variable

  Natural Gas     4,893,700     $4.95       $ 3.71     $6.3       $ (0.2)      $5.9       $ —     
  NGL     2,464,610     $55.66       $ 53.90     $9.6       $ (5.3)      $0.5       $ (8.7
  Crude Oil     1,702,935     $91.78       $ 93.71     $6.0       $ (9.3)      $3.7       $ (10.0

Receive variable/pay variable

  Natural Gas     45,206,000     $3.78       $ 3.75     $1.1       $ (0.1)      $0.8       $ (0.1

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     13,153,882     $3.81       $ 3.76     $0.7       $ —        $0.5       $ —     
  NGL     1,201,223     $60.41       $ 59.77     $0.9       $ (0.1)      $0.4       $ (0.1
  Crude Oil     1,200     $93.79       $ 73.79     $—          $ —        $—          $ —     

Pay fixed

  Power (4)     42,924     $32.40       $ 42.82     $—          $ (0.4)      $—          $ (0.3

Portion of contracts maturing in 2014

             

Swaps

             

Receive variable/pay fixed

  Natural Gas     21,870     $4.16       $ 5.22     $—          $ —        $—          $ —     

Receive fixed/pay variable

  Natural Gas     912,500     $4.09       $ 4.18     $—          $ (0.1)      $—          $ —     
  NGL     490,925     $69.18       $ 67.38     $1.7       $ (0.8)      $0.8       $ (1.9
  Crude Oil     1,301,955     $94.21       $ 91.49     $5.8       $ (2.3)      $4.9       $ (3.1

Receive variable/pay variable

  Natural Gas     7,212,500     $4.19       $ 4.17     $0.2       $ —        $0.1       $ —     

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     8,731,275     $4.22       $ 4.17     $0.5       $ —        $0.1       $ —     

Pay fixed

  Power (4)     58,608     $33.57       $ 46.58     $—          $ (0.8)      $—          $ (0.5

Portion of contracts maturing in 2015

             

Swaps

               

Receive fixed/pay variable

  NGL     109,500     $88.36       $ 80.17     $1.0       $ (0.1)      $0.7       $ (0.2
  Crude Oil     865,415     $97.72       $ 89.11     $7.4       $ (0.1)      $6.0       $ (0.4

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     6,013,425     $4.43       $ 4.37     $0.4       $ —        $0.1       $ —     

Portion of contracts maturing in 2016

             

Swaps

               

Receive fixed/pay variable

  Crude Oil     45,750     $99.31       $ 87.60     $0.5       $ —        $0.4       $ —     

Physical Contracts

               

Receive variable/pay variable

  Natural Gas     783,240     $4.67       $ 4.55     $0.1       $ —        $0.1       $ —     

 

(1) 

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

(2) 

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

(3) 

The fair value is determined based on quoted market prices at September 30, 2012 and December 31, 2011, 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 $0.8 million of losses at September 30, 2012 and December 31, 2011.

(4) 

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

 

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The following table provides summarized information about the fair values of expected cash flows of our outstanding commodity options at September 30, 2012 and December 31, 2011.

 

      At September 30, 2012      At December 31, 2011  
     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 2012

  

                 

Puts (purchased)

   NGL      602,784      $ 39.92      $ 30.79      $ 6.7      $ —         $ 7.3      $ —     
   Crude Oil      16,100      $ 99.00      $ 92.73      $ 0.1      $ —         $ 0.7      $ —     

Portion of option contracts maturing in 2013

  

                 

Puts (purchased)

   Natural Gas      1,642,500      $ 4.18      $ 3.70      $ 1.1      $ —         $ 1.2      $ —     
   NGL      457,000      $ 32.29      $ 29.92      $ 3.8      $ —         $ 0.9      $ —     

 

(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 September 30, 2012 and December 31, 2011, 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 September 30, 2012 and at December 31, 2011.

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

 

     September 30,
2012
    December 31,
2011
 
     (in millions)  

Counterparty Credit Quality*

    

AAA

   $ —        $ (0.2

AA

     (119.4     (98.4

A

     (172.4     (160.7

Lower than A

     2.3       4.8  
  

 

 

   

 

 

 
   $ (289.5   $ (254.5
  

 

 

   

 

 

 

 

* As determined by nationally-recognized statistical ratings organizations.

Item 4. Controls and Procedures

MATERIAL WEAKNESS PREVIOUSLY DISCLOSED

We disclosed in Item 9A. Controls and Procedures of our Annual Report on Form 10-K, for the year ended December 31, 2011, that we had identified a material weakness in our internal control over financial reporting with respect to our wholly-owned trucking and NGL marketing subsidiary related to intentional misconduct and collusion of local management and staff that resulted in accounting misstatements. We determined that these misstatements had no material effect on our consolidated financial statements for the year ended December 31, 2011 or any prior years during which the activities above occurred.

The principal factors at the referenced subsidiary that contributed to the material weakness were: 1) absence of appropriate tone and control culture, 2) controls that were not effective to ensure accurate and timely reporting of assets and liabilities in the instance of collusion by local management and staff, and 3) monitoring controls were not sufficient to detect or deter circumvention of accounting controls or accounting misstatements timely.

 

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REMEDIATION

Management, with the participation of the principal executive officer and principal financial officer, implemented changes to the Partnership’s internal control over financial reporting related to the referenced subsidiary to remediate the material weakness described above. The following changes to the Partnership’s internal control systems and procedures related to the referenced subsidiary included:

Changes Made in Fourth Quarter of 2011

 

   

We have appointed replacements for management at the subsidiary, who separated from the organization.

Changes Made in First Quarter of 2012

 

   

A new accounting manager of the subsidiary was appointed.

 

   

We implemented new centralized reporting structures for various groups, including risk management and information technology.

Changes Made in Second Quarter of 2012

 

   

We centralized critical control functions, including accounting, contract administration, and risk management into the Partnership’s corporate office, which eliminated the need for the initial implementation of an additional layer of review of payments and accounting activities at the subsidiary.

Changes Made in Third Quarter of 2012

 

   

We retrained all of the personnel in addition to our ongoing annual training process at the referenced subsidiary on our statement of Business Conduct, Whistleblower, and Conflicts of Interest policies.

Certain of the remediation measures described above are subject to our internal controls testing and evaluation processes which we are in the process of completing. We believe that these measures as designed will remediate the identified material weakness and strengthen internal control over financial reporting. However, these changes have not been in operation for a sufficient period of time to effectively measure their operating effectiveness. As we continue to evaluate and enhance our internal control over financial reporting, we may determine that additional measures need to be taken to address the material weakness or that we need to modify or otherwise adjust the remediation measures described above.

DISCLOSURE CONTROLS AND PROCEDURES

We and Enbridge maintain systems of disclosure controls and procedures designed to provide reasonable assurance that we are able to record, process, summarize and report the information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, or the Exchange Act, within the time periods specified in the rules and forms of the Securities and Exchange Commission, and that such information is accumulated and communicated to our management, including our principal executive and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our principal executive and principal financial officers, has evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2012. Based upon that evaluation, our principal executive and principal financial officers concluded that our disclosure controls and procedures are not effective at the reasonable assurance level because of the material weakness discussed above. In conducting this assessment, our management relied on similar evaluations conducted by employees of Enbridge affiliates who provide certain treasury, accounting and other services on our behalf.

 

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CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

The changes to our internal control over financial reporting described above under “Remediation – Changes Made in Third Quarter of 2012” occurred during the three month period ended September 30, 2012. These changes have materially affected the Partnership’s internal control over financial reporting as it relates to the referenced subsidiary.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

There have been no material changes to risk factors as previously disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

Item 6. Exhibits

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

 

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SIGNATURES

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

 

 

ENBRIDGE ENERGY PARTNERS, L.P.

(Registrant)

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

as delegate of Enbridge Energy Company, Inc.

as General Partner

Date: October 31, 2012   By:  

/s/ Mark A. Maki

   

Mark A. Maki

President

(Principal Executive Officer)

Date: October 31, 2012   By:  

/s/ Stephen J. Neyland

   

Stephen J. Neyland

Vice President, Finance

(Principal Financial Officer)

 

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Index of Exhibits

Each exhibit identified below is filed as a part of this Quarterly Report on Form 10-Q. Exhibits included in

this filing are designated by an asterisk; all exhibits not so designated are incorporated by reference to a prior filing as indicated.

 

Exhibit
Number

  

Description

 10.1    Credit Agreement, dated as of September 26, 2011, by and among the Partnership, the lenders from time to time parties thereto, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer and Royal Bank of Canada as a L/C Issuer (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K, filed on September 29, 2011).
 10.2 *    First Amendment to Credit Agreement, dated effective as of September 30, 2011, among the Partnership, the lenders parties thereto, and Bank of America, N.A., as Administrative Agent.
 10.3 *    Extension Agreement and Second Amendment to Credit Agreement, dated effective as of September 26, 2012, among the Partnership, the lenders parties thereto, and Bank of America, N.A., as Administrative Agent.
 31.1*    Certification of Principal Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 31.2*    Certification of Principal Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 32.1*    Certification of Principal Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 32.2*    Certification of Principal Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS*    XBRL Instance Document.
101.SCH*    XBRL Taxonomy Extension Schema Document.
101.CAL*    XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*    XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*    XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*    XBRL Taxonomy Extension Presentation Linkbase Document.

 

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