10-Q 1 form10q_3q2011.htm KMP 10Q 3Q 2011 form10q_3q2011.htm

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.  20549
 
F O R M   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, 2011
 
or
 
[   ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from _____to_____
 
Commission file number:  1-11234
 

KINDER MORGAN ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)
 

Delaware
  
76-0380342
(State or other jurisdiction of
incorporation or organization)
  
(I.R.S. Employer
Identification No.)

 
500 Dallas Street, Suite 1000, Houston, Texas 77002
(Address of principal executive offices)(zip code)
Registrant’s telephone number, including area code: 713-369-9000
 

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 Website, 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.  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 230,901,187 common units outstanding as of October 28, 2011.


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES

   
Page
Number
 
PART I.   FINANCIAL INFORMATION
 
     
Item 1.
Financial Statements (Unaudited)                                                                                                                            
3
 
Consolidated Statements of Income - Three and Nine Months Ended September 30, 2011 and 2010
 
Consolidated Balance Sheets – September 30, 2011 and December 31, 2010
 
Consolidated Statements of Cash Flows – Nine Months Ended September 30, 2011 and 2010
 
Notes to Consolidated Financial Statements                                                                                                                       
     
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
47
 
General and Basis of Presentation                                                                                                                       
 
Critical Accounting Policies and Estimates                                                                                                                       
 
Results of Operations                                                                                                                       
 
Financial Condition                                                                                                                       
 
Recent Accounting Pronouncements                                                                                                                       
 
Information Regarding Forward-Looking Statements                                                                                                                       
     
Item 3.
Quantitative and Qualitative Disclosures About Market Risk                                                                                                                            
     
Item 4.
Controls and Procedures                                                                                                                            
     
     
     
 
PART II.   OTHER INFORMATION
 
     
Item 1.
Legal Proceedings                                                                                                                            
     
Item 1A.
Risk Factors                                                                                                                            
     
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds                                                                                                                            
     
Item 3.
Defaults Upon Senior Securities
     
Item 4.
(Removed and Reserved)                                                                                                                            
     
Item 5.
Other Information                                                                                                                            
     
Item 6.
Exhibits                                                                                                                            
     
 
Signature                                                                                                                            
     



PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
(In Millions Except Per Unit Amounts)
(Unaudited)

   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Revenues
                       
Natural gas sales
  $ 938.9     $ 965.7     $ 2,594.9     $ 2,831.3  
Services
    780.1       758.7       2,317.6       2,248.9  
Product sales and other
    476.1       335.6       1,294.7       1,070.9  
Total Revenues
    2,195.1       2,060.0       6,207.2       6,151.1  
                                 
Operating Costs, Expenses and Other
                               
Gas purchases and other costs of sales
    942.5       964.6       2,641.5       2,829.2  
Operations and maintenance
    411.8       328.3       1,199.9       1,098.7  
Depreciation, depletion and amortization
    253.4       224.1       704.6       674.6  
General and administrative
    100.5       93.6       387.1       288.1  
Taxes, other than income taxes
    38.9       41.9       140.8       128.1  
Other expense (income)
    (0.9 )     0.2       (14.9 )     (6.4 )
Total Operating Costs, Expenses and Other
    1,746.2       1,652.7       5,059.0       5,012.3  
                                 
Operating Income
    448.9       407.3       1,148.2       1,138.8  
                                 
Other Income (Expense)
                               
Earnings from equity investments
    72.6       53.7       213.9       155.6  
Amortization of excess cost of equity investments
    (1.8 )     (1.4 )     (4.9 )     (4.3 )
Interest expense
    (133.4 )     (134.0 )     (395.6 )     (374.9 )
Interest income
    6.3       5.0       17.4       17.5  
Loss on remeasurement of previously held equity interest in KinderHawk (Note 2)
    (167.2 )     -       (167.2 )     -  
Other, net
    3.1       5.4       11.1       9.8  
Total Other Income (Expense)
    (220.4 )     (71.3 )     (325.3 )     (196.3 )
                                 
Income Before Income Taxes
    228.5       336.0       822.9       942.5  
                                 
Income Tax (Expense) Benefit
    (12.2 )     (13.6 )     (33.8 )     (27.6 )
                                 
Net Income
    216.3       322.4       789.1       914.9  
                                 
Net Income Attributable to Noncontrolling Interests
    (1.8 )     (1.6 )     (6.3 )     (7.6 )
                                 
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
  $ 214.5     $ 320.8     $ 782.8     $ 907.3  
                                 
Calculation of Limited Partners’ Interest in Net Income (Loss)
                               
Attributable to Kinder Morgan Energy Partners, L.P.:
                               
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
  $ 214.5     $ 320.8     $ 782.8     $ 907.3  
Less: General Partner’s Interest
    (298.2 )     (267.3 )     (871.0 )     (609.0 )
Limited Partners’ Interest in Net Income (Loss)
  $ (83.7 )   $ 53.5     $ (88.2 )   $ 298.3  
                                 
Limited Partners’ Net Income (Loss) per Unit
  $ (0.25 )   $ 0.17     $ (0.27 )   $ 0.98  
                                 
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income (Loss) per Unit
    331.1       310.7       323.3       304.7  
                                 
Per Unit Cash Distribution Declared
  $ 1.16     $ 1.11     $ 3.45     $ 3.27  

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



KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
(In Millions)

   
September 30,
2011
   
December 31, 2010
 
   
(Unaudited)
       
ASSETS
           
Current assets
           
Cash and cash equivalents
  $ 271.0     $ 129.1  
Restricted deposits
    0.7       50.0  
Accounts, notes and interest receivable, net
    823.6       951.8  
Inventories
    101.3       92.0  
Gas in underground storage
    27.2       2.2  
Fair value of derivative contracts
    135.2       24.0  
Other current assets
    47.0       37.6  
Total current assets
    1,406.0       1,286.7  
                 
Property, plant and equipment, net
    15,344.1       14,603.9  
Investments
    3,272.5       3,886.0  
Notes receivable
    164.0       115.0  
Goodwill
    1,303.3       1,233.6  
Other intangibles, net
    1,167.5       302.2  
Fair value of derivative contracts
    703.4       260.7  
Deferred charges and other assets
    217.5       173.0  
Total Assets
  $ 23,578.3     $ 21,861.1  
                 
LIABILITIES AND PARTNERS’ CAPITAL
               
Current liabilities
               
Current portion of debt
  $ 1,844.4     $ 1,262.4  
Cash book overdrafts
    40.9       32.5  
Accounts payable
    624.4       630.9  
Accrued interest
    96.9       239.6  
Accrued taxes
    100.6       44.7  
Deferred revenues
    91.9       96.6  
Fair value of derivative contracts
    71.9       281.5  
Accrued other current liabilities
    199.3       176.0  
Total current liabilities
    3,070.3       2,764.2  
                 
Long-term liabilities and deferred credits
               
Long-term debt
               
Outstanding
    10,662.2       10,277.4  
Value of interest rate swaps
    1,071.2       604.9  
Total Long-term debt
    11,733.4       10,882.3  
Deferred income taxes
    243.0       248.3  
Fair value of derivative contracts
    21.4       172.2  
Other long-term liabilities and deferred credits
    785.7       501.6  
Total long-term liabilities and deferred credits
    12,783.5       11,804.4  
                 
Total Liabilities
    15,853.8       14,568.6  
                 
Commitments and contingencies (Notes 4 and 10)
               
Partners’ Capital
               
Common units
    4,354.7       4,282.2  
Class B units
    44.9       63.1  
i-units
    2,807.1       2,807.5  
General partner
    257.7       244.3  
Accumulated other comprehensive income (loss)
    172.6       (186.4 )
Total Kinder Morgan Energy Partners, L.P. partners’ capital
    7,637.0       7,210.7  
Noncontrolling interests
    87.5       81.8  
Total Partners’ Capital
    7,724.5       7,292.5  
Total Liabilities and Partners’ Capital
  $ 23,578.3     $ 21,861.1  

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


KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
(In Millions)
(Unaudited)

   
Nine Months Ended
September 30,
 
   
2011
   
2010
 
Cash Flows From Operating Activities
           
Net Income
  $ 789.1     $ 914.9  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    704.6       674.6  
Amortization of excess cost of equity investments
    4.9       4.3  
Loss on remeasurement of previously held equity interest in KinderHawk (Note 2)
    167.2       -  
Noncash compensation expense allocated from parent (Note 9)
    89.9       3.7  
Earnings from equity investments
    (213.9 )     (155.6 )
Distributions from equity investments
    200.9       154.9  
Proceeds from termination of interest rate swap agreements
    73.0       -  
Changes in components of working capital:
               
Accounts receivable
    28.2       105.0  
Inventories
    9.3       (12.8 )
Other current assets
    (1.8 )     12.9  
Accounts payable
    (9.3 )     (26.8 )
Accrued interest
    (142.8 )     (125.6 )
Accrued taxes
    47.4       32.7  
Accrued liabilities
    (2.4 )     2.8  
Rate reparations, refunds and other litigation reserve adjustments
    160.4       (48.3 )
Other, net
    70.4       (9.4 )
Net Cash Provided by Operating Activities
    1,975.1       1,527.3  
                 
Cash Flows From Investing Activities
               
Acquisitions of investments
    (901.0 )     (929.7 )
Acquisitions of assets
    (44.0 )     (243.1 )
Capital expenditures
    (837.7 )     (722.1 )
Sale or casualty of property, plant and equipment, and other net assets net of removal costs
    29.0       21.5  
Net proceeds from margin and restricted deposits
    55.7       21.7  
Contributions to equity investments
    (297.0 )     (209.8 )
Distributions from equity investments in excess of cumulative earnings
    165.3       153.2  
Other, net
    3.0       -  
Net Cash Used in Investing Activities
    (1,826.7 )     (1,908.3 )
                 
Cash Flows From Financing Activities
               
Issuance of debt
    6,356.4       5,704.2  
Payment of debt
    (5,538.1 )     (4,601.0 )
Repayments from related party
    29.3       1.3  
Debt issue costs
    (17.6 )     (22.5 )
Increase (Decrease) in cash book overdrafts
    8.4       (4.4 )
Proceeds from issuance of common units
    813.3       636.6  
Contributions from noncontrolling interests
    15.4       10.2  
Distributions to partners and noncontrolling interests:
               
Common units
    (762.1 )     (674.2 )
Class B units
    (18.2 )     (17.1 )
General Partner
    (858.5 )     (591.4 )
Noncontrolling interests
    (20.5 )     (16.7 )
Other, net
    0.5       -  
Net Cash Provided by Financing Activities
    8.3       425.0  
                 
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    (14.8 )     1.0  
                 
Net increase in Cash and Cash Equivalents
    141.9       45.0  
Cash and Cash Equivalents, beginning of period
    129.1       146.6  
Cash and Cash Equivalents, end of period
  $ 271.0     $ 191.6  

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



KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS   (continued)
(In Millions)
(Unaudited)

       
   
Nine Months Ended
September 30,
 
   
2011
   
2010
 
Noncash Investing and Financing Activities
           
Assets acquired by the assumption or incurrence of liabilities
  $ 179.5     $ 12.5  
Assets acquired by the issuance of common units
  $ 23.7     $ 81.7  
Contribution of net assets to investments
  $ 7.9     $ -  
Sale of investment ownership interest in exchange for note
  $ 4.1     $ -  
                 
Supplemental Disclosures of Cash Flow Information
               
Cash paid during the period for interest (net of capitalized interest)
  $ 510.2     $ 456.6  
Cash paid during the period for income taxes
  $ 9.4     $ (2.8 )

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



KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
(Unaudited)
 
 
1.  General
 
Organization
 
Kinder Morgan Energy Partners, L.P. is a leading pipeline transportation and energy storage company in North America, and unless the context requires otherwise, references to “we,” “us,” “our,” “KMP” or the “Partnership” are intended to mean Kinder Morgan Energy Partners, L.P. and its consolidated subsidiaries.  We own an interest in or operate approximately 28,000 miles of pipelines and 180 terminals, and conduct our business through five reportable business segments (described further in Note 8).  Our pipelines transport natural gas, refined petroleum products, crude oil, carbon dioxide and other products, and our terminals store petroleum products and chemicals, and handle such products as ethanol, coal, petroleum coke and steel.  We are also the leading provider of carbon dioxide, commonly called CO2, for enhanced oil recovery projects in North America.  Our general partner is owned by Kinder Morgan, Inc., as discussed below.
 
Kinder Morgan, Inc., Kinder Morgan Kansas, Inc. and Kinder Morgan G.P., Inc.
 
Kinder Morgan, Inc., a Delaware corporation and referred to as KMI in this report, indirectly owns all the common stock of Kinder Morgan Kansas, Inc.  Kinder Morgan Kansas, Inc. is a Kansas corporation and indirectly owns all the common stock of our general partner, Kinder Morgan G.P., Inc., a Delaware corporation.  In July 2007, our general partner issued and sold 100,000 shares of Series A fixed-to-floating rate term cumulative preferred stock due 2057.  The consent of holders of a majority of these preferred shares is required with respect to a commencement of or a filing of a voluntary bankruptcy proceeding with respect to us or two of our subsidiaries, SFPP, L.P. and Calnev Pipe Line LLC.  As of September 30, 2011, KMI and its consolidated subsidiaries owned, through KMI’s general and limited partner interests in us and its ownership of shares issued by its subsidiary Kinder Morgan Management, LLC (discussed following), an approximate 12.4% interest in us.
 
KMI was formed August 23, 2006 as a Delaware limited liability company principally for the purpose of acquiring (through a wholly-owned subsidiary) all of the common stock of Kinder Morgan Kansas, Inc.  The merger, referred to in this report as the going-private transaction, closed on May 30, 2007 with Kinder Morgan Kansas, Inc. continuing as the surviving legal entity.
 
On February 10, 2011, KMI converted from a Delaware limited liability company named Kinder Morgan Holdco LLC to a Delaware corporation named Kinder Morgan, Inc., and its outstanding units were converted into classes of capital stock.  On February 16, 2011, KMI completed the initial public offering of its common stock.  All of the common stock that was sold in the offering was sold by existing investors, consisting of funds advised by or affiliated with Goldman, Sachs & Co., Highstar Capital LP, The Carlyle Group and Riverstone Holdings LLC.  No members of management sold shares in the offering and KMI did not receive any proceeds from the offering.  KMI’s common stock trades on the New York Stock Exchange under the symbol “KMI.”
 
Subsequent Event
 
On October 16, 2011, KMI and El Paso Corporation announced a definitive agreement whereby KMI will acquire all of the outstanding shares of El Paso in a transaction that will create an energy company having an enterprise value of approximately $94 billion and 80,000 miles of pipelines.  The total purchase price, including the assumption of debt outstanding at both El Paso Corporation and El Paso Pipeline Partners, L.P., is approximately $38 billion.  El Paso Corporation owns a 42% limited partner interest and the 2% general partner interest in El Paso Pipeline Partners, L.P.  The transaction is expected to close in the second quarter of 2012 and is subject to customary regulatory approvals.
 
 
Kinder Morgan Management, LLC
 
Kinder Morgan Management, LLC, referred to as KMR in this report, is a Delaware limited liability company.  Our general partner owns all of KMR’s voting securities and, pursuant to a delegation of control agreement, has delegated to KMR, to the fullest extent permitted under Delaware law and our partnership agreement, all of its power and authority to manage and control our business and affairs, except that KMR cannot take certain specified actions without the approval of our general partner.  KMR’s shares represent limited liability company interests and trade on the New York Stock Exchange under the symbol “KMR.”
 
More information about the entities referred to above and the delegation of control agreement is contained in our Annual Report on Form 10-K for the year ended December 31, 2010.  In this report, we refer to our Annual Report on Form 10-K for the year ended December 31, 2010 as our 2010 Form 10-K, and we refer to our Amended Annual Report on Form 10-K for the year ended December 31, 2010, as our 2010 Form 10-K/A.  The sole purpose of our amended filing was to include the signature line of the Report of Independent Registered Public Accounting Firm included in our original filing’s Item 8 “Financial Statements and Supplementary Data.”
 
Basis of Presentation
 
We have prepared our accompanying unaudited consolidated financial statements under the rules and regulations of the United States Securities and Exchange Commission.  These rules and regulations conform to the accounting principles contained in the Financial Accounting Standards Board’s Accounting Standards Codification, the single source of generally accepted accounting principles in the United States of America and referred to in this report as the Codification. Under such rules and regulations, we have condensed or omitted certain information and notes normally included in financial statements prepared in conformity with the Codification.  We believe, however, that our disclosures are adequate to make the information presented not misleading.
 
In addition, our consolidated financial statements reflect normal adjustments, and also recurring adjustments that are, in the opinion of our management, necessary for a fair statement of our financial results for the interim periods, and certain amounts from prior periods have been reclassified to conform to the current presentation.  Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2010 Form 10-K/A.
 
Our accounting records are maintained in United States dollars, and all references to dollars are United States dollars, except where stated otherwise.  Canadian dollars are designated as C$.  Our consolidated financial statements include our accounts and those of our operating partnerships and their majority-owned and controlled subsidiaries, and all significant intercompany items have been eliminated in consolidation.
 
In addition, our financial statements are consolidated into the consolidated financial statements of KMI; however, except for the related party transactions described in Note 9 “Related Party Transactions—Asset Acquisitions,” KMI is not liable for, and its assets are not available to satisfy, the obligations of us and/or our subsidiaries and vice versa.  Responsibility for payments of obligations reflected in our or KMI’s financial statements is a legal determination based on the entity that incurs the liability.  Furthermore, the determination of responsibility for payment among entities in our consolidated group of subsidiaries is not impacted by the consolidation of our financial statements into the consolidated financial statements of KMI.
 
Limited Partners’ Net Income(Loss) per Unit
 
We compute Limited Partners’ Net Income (Loss) per Unit by dividing our limited partners’ interest in net income (loss) by the weighted average number of units outstanding during the period.  The overall computation, presentation, and disclosure requirements for our Limited Partners’ Net Income (Loss) per Unit  are made in accordance with the “Earnings per Share” Topic of the Codification.
 

2.  Acquisitions and Divestitures
 
Acquisitions
 
Watco Companies, LLC
 
On January 3, 2011, we purchased 50,000 Class A preferred shares of Watco Companies, LLC for $50.0 million in cash in a private transaction.  In connection with our purchase of these preferred shares, the most senior equity security of Watco, we entered into a limited liability company agreement with Watco that provides us certain priority and participating cash distribution and liquidation rights.  Pursuant to the agreement, we receive priority, cumulative cash distributions from the preferred shares at a rate of 3.25% per quarter, and we participate partially in additional profit distributions at a rate equal to 0.5%.  The preferred shares have no conversion features and hold no voting powers, but do provide us certain approval rights, including the right to appoint one of the members to Watco’s Board of Managers.  As of December 31, 2010, we placed our $50.0 million investment in a cash escrow account and we included this amount within “Restricted deposits” on our accompanying consolidated balance sheet.  As of September 30, 2011, our net equity investment in Watco totaled $51.6 million and is included within “Investments” on our accompanying consolidated balance sheet.  We account for our investment under the equity method of accounting, and we include it in our Terminals business segment.
 
Watco Companies, LLC is a privately owned, Pittsburg, Kansas based transportation company that was formed in 1983.  It is the largest privately held short line railroad company in the United States, operating 22 short line railroads on approximately 3,500 miles of leased and owned track.  It also operates transload/intermodal and mechanical services divisions.  Our investment provides capital to Watco for further expansion of specific projects, complements our existing terminal network, provides our customers more transportation services for many of the commodities that we currently handle, and offers us the opportunity to share in additional growth opportunities through new projects.
 
Deeprock North, LLC
 
On February 17, 2011, Deeprock Energy Resources, LLC, Mecuria Energy Trading, Inc., and our subsidiary Kinder Morgan Cushing LLC, entered into formal agreements for a crude oil storage joint venture located in Cushing, Oklahoma. On this date, we contributed $15.9 million for a 50% ownership interest in an existing crude oil tank farm that has storage capacity of one million barrels, and we expect to invest an additional $8.8 million for the construction of three new storage tanks that will provide incremental storage capacity of 750,000 barrels.  The new tanks are expected to be placed in service during the fourth quarter of 2011.  The joint venture is named Deeprock North, LLC.  Deeprock Energy owns a 12.02% member interest in Deeprock North, LLC and will remain construction manager and operator of the joint venture.  Mecuria owns the remaining 37.98% member interest and will remain the anchor tenant for the joint venture’s crude oil capacity for the next five years with an option to extend.  In addition, we entered into a development agreement with Deeprock Energy that gives us an option to participate in future expansions on Deeprock’s remaining 254 acres of undeveloped land.
 
We account for our investment under the equity method of accounting, and our investment and our pro rata share of Deeprock North LLC’s operating results are included as part of our Terminals business segment.  As of September 30, 2011, our net equity investment in Deeprock North, LLC totaled $22.3 million and is included within “Investments” on our accompanying consolidated balance sheet.
 
TGS Development, L.P. Terminal Acquisition 
 
On June 10, 2011, we acquired a newly constructed petroleum coke terminal located in Port Arthur, Texas from TGS Development, L.P. (TGSD) for an aggregate consideration of $74.1 million, consisting of $42.9 million in cash, $23.7 million in common units, and an obligation to pay additional consideration of $7.5 million.  We estimate our remaining $7.5 million obligation will be paid to TGSD approximately one year from the closing (in May or June 2012), and will be settled in a combination of cash and common units, depending on TGSD’s election.
 
All of the acquired assets are located in Port Arthur, Texas, and include long-term contracts to provide petroleum coke handling and cutting services to improve the refining of heavy crude oil at Total Petrochemicals USA Inc.’s recently expanded Port Arthur refinery.  The refinery is expected to produce more than one million tons of petroleum coke annually.  Based on our measurement of fair values for all of the identifiable tangible and intangible assets acquired, we assigned $42.6 million of our combined purchase price to “Property, plant and equipment, net,” and the remaining $31.5 million to “Other intangibles, net,” representing the combined fair values of two separate intangible customer contracts with Total.  The acquisition complements our existing Gulf Coast bulk terminal facilities and expands our pre-existing petroleum coke handling operations.  All of the acquired assets are included as part of our Terminals business segment.
 
KinderHawk Field Services LLC and EagleHawk Field Services LLC
 
Effective July 1, 2011, we acquired from Petrohawk Energy Corporation both the remaining 50% equity ownership interest in KinderHawk Field Services LLC that we did not already own and a 25% equity ownership interest in Petrohawk’s natural gas gathering and treating business located in the Eagle Ford shale formation in South Texas for an aggregate consideration of $912.1 million, consisting of $835.1 million in cash and assumed debt of $77.0 million (representing 50% of KinderHawk’s borrowings under its bank credit facility as of July 1, 2011).  We then repaid the outstanding $154.0 million of borrowings and following this repayment, KinderHawk had no outstanding debt.
 
Following our acquisition of the remaining ownership interest on July 1, 2011, we changed our method of accounting from the equity method to full consolidation, and due to the fact that we acquired a controlling financial interest in KinderHawk, we remeasured our previous 50% equity investment in KinderHawk to its fair value.  We recognized a $167.2 million non-cash loss as a result of this remeasurement.  The loss amount represents the excess of the carrying value of our investment ($910.2 million as of July 1, 2011) over its fair value ($743.0 million), and we reported this loss separately within the “Other Income (Expense)” section in our accompanying consolidated statements of income for the three and nine months ended September 30, 2011.
 
We then measured the fair values of the acquired identifiable tangible and intangible assets and the assumed liabilities on the acquisition date, and assigned the following amounts:
 
 
$35.5 million to current assets, primarily consisting of trade receivables and materials and supplies inventory;
 
 
$641.6 million to property, plant and equipment;
 
 
$93.4 million to our 25% investment in EagleHawk;
 
 
$883.2 million to a long-term intangible customer contract, representing the contract value of natural gas gathering services to be performed for Petrohawk over an approximate 20-year period; less

 
$92.8 million assigned to assumed liabilities, not including $77.0 million for the 50% of KinderHawk’s borrowings under its bank credit facility that we were previously responsible for.
 
Based on the excess of (i) the consideration we transferred ($912.1 million) and the fair value of our previously held interest ($743.0 million); over (ii) the combined fair value of net assets acquired ($1,560.9 million), we recognized $94.2 million of “Goodwill.”  This goodwill intangible asset represents the future economic benefits expected to be derived from this strategic acquisition that are not assignable to other individually identifiable, separately recognizable assets acquired.  We believe the primary items that generated the goodwill are the value of the synergies created by expanding our natural gas gathering operations, and furthermore, we expect this entire amount of goodwill to be deductible for tax purposes.
 
KinderHawk Field Services LLC owns and operates the largest natural gas gathering and midstream business in the Haynesville shale formation located in northwest Louisiana, consisting of more than 400 miles of pipeline with over 2.0 billion cubic feet per day of pipeline capacity.  Currently, it gathers approximately 1.0 billion cubic feet of natural gas per day.  We operate KinderHawk Field Services LLC, and we acquired our original 50% ownership interest in KinderHawk Field Services LLC from Petrohawk on May 21, 2010.
 
The Eagle Ford natural gas gathering joint venture is named EagleHawk Field Services LLC, and we account for our 25% investment under the equity method of accounting.  Petrohawk operates EagleHawk Field Services LLC and owns the remaining 75% ownership interest.  The joint venture owns two midstream gathering systems in and around Petrohawk’s Hawkville and Black Hawk areas of Eagle Ford and combined, the joint venture’s assets will consist of more than 280 miles of gas gathering pipelines and approximately 140 miles of condensate lines to be in service by the end of 2011.  It also has a life of lease dedication of Petrohawk’s Eagle Ford reserves that provides Petrohawk and other Eagle Ford producers with gas and condensate gathering, treating and condensate stabilization services.
 
The acquisition of the remaining ownership interest in KinderHawk and the equity ownership interest in EagleHawk complemented and expanded our existing natural gas gathering operations, and all of the acquired assets are included in our Natural Gas Pipelines business segment.  Additionally, on August 25, 2011, mining and oil company BHP Billiton completed its previously announced acquisition of Petrohawk Energy Corporation through a short-form merger under Delaware law.  The merger was closed with Petrohawk being the surviving corporation as a wholly owned subsidiary of BHP Billiton.  The acquisition will not affect the terms of our contracts with Petrohawk.
 
Pro Forma Information                                                   
 
Pro forma consolidated income statement information that gives effect to all of the acquisitions we have made and all of the joint ventures we have entered into since January 1, 2010 as if they had occurred as of January 1, 2010 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.
 
Divestitures
 
Megafleet Towing Co., Inc. Assets
 
On February 9, 2011, we sold a marine vessel to Kirby Inland Marine, L.P., and additionally, we and Kirby formed a joint venture named Greens Bayou Fleeting, LLC.  Pursuant to the joint venture agreement, we sold our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009 to the joint venture for $4.1 million in cash and a 49% ownership interest in the joint venture.  Kirby then made cash contributions to the joint venture in exchange for the remaining 51% ownership interest.  Related to the above transactions, we recorded a loss of $5.5 million ($4.1 million after tax) in the fourth quarter of 2010 to write down the carrying value of the net assets to be sold to their estimated fair values as of December 31, 2010.
 
In the first quarter of 2011, after final reconciliation and measurement of all of the net assets sold, we recognized a combined $2.2 million increase in income from the sale of these net assets, primarily consisting of a $1.9 million reduction in income tax expense, which is included within the caption “Income Tax (Expense) Benefit” in our accompanying consolidated statement of income for the nine months ended September 30, 2011.  Additionally, the sale of our ownership interest resulted in a $10.6 million non-cash reduction in our goodwill (see Note 3), and was a transaction with a related party (see Note 9).  Information about our acquisition of assets from Megafleet Towing Co., Inc. is described more fully in Note 3 to our consolidated financial statements included in our 2010 Form 10-K/A.
 
River Consulting, LLC and Devco USA, L.L.C.                   
 
Effective April 1, 2011, we sold 51% ownership interests in two separate wholly-owned subsidiaries to two separate buyers, for an aggregate consideration of $8.1 million, consisting of a $4.1 million note receivable, $1.0 million in cash, and a $3.0 million receivable for the settlement of working capital items.  Following the sale, we continue to own 49% membership interests in both River Consulting, LLC, a company engaged in the business of providing engineering, consulting and management services, and Devco USA, L.L.C., a company engaged in the business of processing, handling and marketing sulfur, and selling related pouring equipment.  At the time of the sale, the combined carrying value of the net assets (and members’ capital on a 100% basis) of both entities totaled approximately $8.8 million and consisted mostly of technology-based assets and trade receivables.  We now account for our retained investments under the equity method of accounting.
 
In the second quarter of 2011, we recognized a $3.6 million pre-tax gain from the sale of these ownership interests (including a $2.1 million gain related to the remeasurement of our retained investment to fair value) and we included this gain within the caption “Other, net” in our accompanying consolidated statements of income for the nine months ended September 30, 2011.  We also recognized a $1.4 million increase in income tax expense related to this gain, which is included within the caption “Income Tax (Expense) Benefit” in our accompanying consolidated statement of income for the nine months ended September 30, 2011.
 
Arrow Terminals B.V.                
 
Effective August 31, 2011, we sold the outstanding share capital of our wholly-owned subsidiary Arrow Terminals B.V. to Pacorini Metals Europe B.V. for an aggregate consideration of $13.3 million in cash.  Arrow Terminals B.V. owns and operates a bulk terminal facility located in the seaport area of Vlissingen, Netherlands.  The terminal is primarily engaged in the business of storing, handling and distributing bulk ferro alloys and general commodities.  Including the removal of our cumulative translation adjustments balance and our estimated costs to sell, we recognized a $1.3 million pre-tax gain from the sale of Arrow Terminals B.V. and we included this gain within the caption “Other expense (income)” in our accompanying consolidated statements of income for the three and nine months ended September 30, 2011.
 
Acquisition Subsequent to September 30, 2011
 
On October 24, 2011, we announced that we have signed a definitive purchase and sale agreement to acquire the natural gas treating assets of SouthTex Treaters for approximately $155.0 million in cash.  SouthTex Treaters is a leading manufacturer, designer and fabricator of natural gas treating plants that are used to remove impurities (carbon dioxide and hydrogen sulfide) from natural gas before it is delivered into gathering systems and transmission pipelines to ensure that it meets pipeline quality specifications.  The acquisition complements and expands our existing natural gas treating business, and all of the acquired operations will be included in our Natural Gas Pipelines business segment.  The transaction is expected to close in the fourth quarter of 2011, and we will then also assign our total purchase price to assets acquired and liabilities assumed.
 
 
3.   Intangibles
 
Goodwill
 
We evaluate goodwill for impairment on May 31 of each year.  For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes, but combined with Products Pipelines for presentation in the table below); (iii) Natural Gas Pipelines; (iv) CO2; (v) Terminals; and (vi) Kinder Morgan Canada.  There were no impairment charges resulting from our May 31, 2011 impairment testing, and no event indicating an impairment has occurred subsequent to that date.
 
The fair value of each reporting unit was determined from the present value of the expected future cash flows from the applicable reporting unit (inclusive of a terminal value calculated using market multiples between six and ten times cash flows) discounted at a rate of 8.0%.  The value of each reporting unit was determined on a stand-alone basis from the perspective of a market participant and represented the price that would be received to sell the unit as a whole in an orderly transaction between market participants at the measurement date.
 
Changes in the gross amounts of our goodwill and accumulated impairment losses for the nine months ended September 30, 2011 are summarized as follows (in millions):
 
   
Products
Pipelines
   
Natural Gas
Pipelines
   
CO2
   
Terminals
   
Kinder Morgan
Canada
   
Total
 
                                     
Historical Goodwill.
  $ 263.2     $ 337.0     $ 46.1     $ 337.9     $ 626.5     $ 1,610.7  
Accumulated impairment losses(a).
    -       -       -       -       (377.1 )     (377.1 )
Balance as of December 31, 2010
    263.2       337.0       46.1       337.9       249.4       1,233.6  
Acquisitions(b).
    -       94.2       -       -       -       94.2  
Disposals(c).
    -       -       -       (11.8 )     -       (11.8 )
Impairments
    -       -       -       -       -       -  
Currency translation adjustments
    -       -       -       -       (12.7 )     (12.7 )
Balance as of September 30, 2011
  $ 263.2     $ 431.2     $ 46.1     $ 326.1     $ 236.7     $ 1,303.3  
__________

(a)
On April 18, 2007, we announced that we would acquire the Trans Mountain pipeline system from KMI, and we completed this transaction on April 30, 2007.  Following the provisions of U.S. generally accepted accounting principles, the consideration of this transaction caused KMI to consider the fair value of the Trans Mountain pipeline system, and to determine whether goodwill related to these assets was impaired.  Based on this determination, KMI recorded a goodwill impairment charge of $377.1 million in the first quarter of 2007, and because we have included all of the historical results of Trans Mountain as though the net assets had been transferred to us on January 1, 2006, this impairment is now included in our accumulated impairment losses. We have no other goodwill impairment losses.
 
(b)
2011 acquisition amount relates to our July 2011 purchase of the remaining 50% ownership interest in KinderHawk Field Services LLC that we did not already own (discussed further in Note 2).
 
(c)
2011 disposal amount consists of (i) $10.6 million related to the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009; and (ii) $1.2 million related to the sale of our subsidiary Arrow Terminals B.V. (both discussed further in Note 2).
 
In addition, we identify any premium or excess cost we pay over our proportionate share of the underlying fair value of net assets acquired and accounted for as investments under the equity method of accounting.  This premium or excess cost is referred to as equity method goodwill and is also not subject to amortization but rather to impairment testing.  For all investments we own containing equity method goodwill, no event or change in circumstances that may have a significant adverse effect on the fair value of our equity investments has occurred during the first nine months of 2011.
 
As of September 30, 2011 and December 31, 2010, we reported $138.2 million and $283.0 million, respectively, in equity method goodwill within the caption “Investments” in our accompanying consolidated balance sheets.  The decrease in our equity method goodwill since December 31, 2010 was due to our July 2011 purchase of the remaining 50% ownership interest in KinderHawk Field Services LLC that we did not already own (discussed further in Note 2).  Effective July 1, 2011, we exchanged our status as an owner of an equity investment in KinderHawk for a full controlling financial interest, and we began accounting for our investment under the full consolidation method.
 
Other Intangibles
 
Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, lease value, and technology-based assets.  These intangible assets have definite lives and are reported separately as “Other intangibles, net” in our accompanying consolidated balance sheets.  Following is information related to our intangible assets subject to amortization (in millions):
 
   
September 30,
2011
   
December 31,
2010
 
Customer relationships, contracts and agreements
           
Gross carrying amount
  $ 1,312.7     $ 399.8  
Accumulated amortization
    (152.0 )     (112.0 )
Net carrying amount
    1,160.7       287.8  
                 
Lease value, technology-based assets and other
               
Gross carrying amount
    10.6       17.9  
Accumulated amortization
    (3.8 )     (3.5 )
Net carrying amount
    6.8       14.4  
                 
Total Other intangibles, net
  $ 1,167.5     $ 302.2  
 
The increase in the carrying amount of our customer relationships, contacts and agreements since December 31, 2010 was mainly due to the acquisition of (i) a natural gas gathering customer contract in July 2011, associated with our purchase of the remaining 50% ownership interest in KinderHawk Field Services LLC that we did not already own; and (ii) two separate petroleum coke handling customer contracts in June 2011, associated with our purchase of terminal assets from TGS Development, L.P.  Both acquisitions are described further in Note 2.
 
We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives.  Among the factors we weigh, depending on the nature of the asset, are the effects of obsolescence, new technology, and competition.  For the three and nine months ended September 30, 2011, the amortization expense on our intangibles totaled $20.9 million and $40.3 million, respectively, and for the same prior year periods, the amortization expense on our intangibles totaled $11.5 million and $33.9 million, respectively. As of September 30, 2011, the weighted average amortization period for our intangible assets was approximately 18.6 years, and our estimated amortization expense for these assets for each of the next five fiscal years (2012 – 2016) is approximately $77.1 million, $73.2 million, $70.1 million, $67.3 million and $63.8 million, respectively.
 

 

 
 
4.  Debt
 
We classify our debt based on the contractual maturity dates of the underlying debt instruments.  We defer costs associated with debt issuance over the applicable term.  These costs are then amortized as interest expense in our consolidated statements of income.
 
The net carrying amount of our debt (including both short-term and long-term amounts and excluding the value of interest rate swap agreements) as of September 30, 2011 and December 31, 2010 was $12,506.6 million and $11,539.8 million, respectively.  The weighted average interest rate on all of our borrowings (both short-term and long-term) was approximately 4.12% during the third quarter of 2011, and approximately 4.42% during the third quarter of 2010.  For the first nine months of 2011 and 2010, the weighted average interest rate on all of our borrowings was approximately 4.28% and 4.34%, respectively.
 
Our outstanding short-term debt as of September 30, 2011 was $1,844.4 million.  The balance consisted of (i) $500.0 million in principal amount of 9.00% senior notes due February 1, 2019, that may be repurchased by us at the option of the holder on February 1, 2012 pursuant to certain repurchase provisions contained in the bond indenture; (ii) $450.0 million in principal amount of 7.125% senior notes due March 15, 2012 (including discount, the notes had a carrying amount of $449.9 million as of September 30, 2011); (iii) $500.0 million in principal amount of 5.850% senior notes due September 15, 2012 (including discount, the notes had a carrying amount of $499.9 million as of September 30, 2011); (iv) $353.0 million of commercial paper borrowings; (v) $23.7 million in principal amount of tax-exempt bonds that mature on April 1, 2024, that are due on demand pursuant to certain standby purchase agreement provisions contained in the bond indenture (our subsidiary Kinder Morgan Operating L.P. “B” is the obligor on the bonds); (vi) a $9.7 million portion of a 5.40% long-term note payable (our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note); (vii) a $7.5 million portion of 5.23% long-term senior notes (our subsidiary Kinder Morgan Texas Pipeline, L.P. is the obligor on the notes); and (viii) a $0.7 million portion of 6.00% long-term note payable (our subsidiary Kinder Morgan Arrow Terminals, L.P. is the obligor on the note).
 
Credit Facility
 
On July 1, 2011, we amended our $2.0 billion three-year, senior unsecured revolving credit facility to, among other things, (i) allow for borrowings of up to $2.2 billion; (ii) extend the maturity of the credit facility from June 23, 2013 to July 1, 2016; (iii) permit an amendment to allow for borrowings of up to $2.5 billion; and (iv) decrease the interest rates and commitment fees for borrowings under this facility.  The credit facility is with a syndicate of financial institutions, and the facility permits us to obtain bids for fixed rate loans from members of the lending syndicate.  Wells Fargo Bank, National Association is the administrative agent, and borrowings under the credit facility can be used for general partnership purposes and as a backup for our commercial paper program.  There were no borrowings under the credit facility as of September 30, 2011 or as of December 31, 2010.
 
Additionally, as of September 30, 2011, the amount available for borrowing under our credit facility was reduced by a combined amount of $584.8 million, consisting of $353.0 million of commercial paper borrowings and $231.8 million of letters of credit, consisting of: (i) a $100.0 million letter of credit that supports certain proceedings with the California Public Utilities Commission involving refined products tariff charges on the intrastate common carrier operations of our Pacific operations’ pipelines in the state of California; (ii) a combined $87.9 million in three letters of credit that support tax-exempt bonds; (iii) a $16.2 million letter of credit that supports debt securities issued by the Express pipeline system; (iv) a $10.7 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (v) a combined $17.0 million in other letters of credit supporting other obligations of us and our subsidiaries.
 
Commercial Paper Program
 
In July 2011, in conjunction with the amendment to our revolving credit facility, we increased our commercial paper program to provide for the issuance of up to $2.2 billion of commercial paper (up from $2.0 billion).  Our unsecured revolving credit facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.
 
As of September 30, 2011, we had $353.0 million of commercial paper outstanding with an average interest rate of 0.35%.  As of December 31, 2010, we had $522.1 million of commercial paper outstanding with an average interest rate of 0.67%.  The borrowings under our commercial paper program were used principally to finance the acquisitions and capital expansions we made during 2011 and 2010, and in the near term, we expect that our short-term liquidity and financing needs will be met primarily through borrowings made under our commercial paper program.
 
 
 
Kinder Morgan Energy Partners, L.P. Senior Notes
 
On March 4, 2011, we completed a public offering of $1.1 billion in principal amount of senior notes in two separate series, consisting of $500 million of 3.500% notes due March 1, 2016, and $600 million of 6.375% notes due March 1, 2041.  We received proceeds from the issuance of the notes, after deducting the underwriting discount, of $1,092.7 million, and we used the proceeds to reduce the borrowings under our commercial paper program.
 
On March 15, 2011, we paid $700 million to retire the principal amount of our 6.75% senior notes that matured on that date.  We used both cash on hand and borrowings under our commercial paper program to repay the maturing senior notes.
 
In addition, on August 17, 2011, we completed a public offering of $750 million in principal amount of senior notes in two separate series, consisting of $375 million of 4.150% notes due March 1, 2022, and $375 million of 5.625% notes due September 1, 2041.  We received proceeds from the issuance of the notes, after deducting the underwriting discount, of $743.3 million, and we used the proceeds to reduce the borrowings under our commercial paper program.
 
 
Subsidiary Debt
 
Kinder Morgan Operating L.P. “A” Debt
 
Effective January 1, 2007, we acquired the remaining approximately 50.2% interest in the Cochin pipeline system that we did not already own.  As part of our purchase price consideration, two of our subsidiaries issued a long-term note payable to the seller having a fair value of $42.3 million.  We valued the debt equal to the present value of amounts to be paid, determined using an annual interest rate of 5.40%.  Our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note, and the principal amount of the note, along with interest, is due in five annual installments of $10.0 million beginning March 31, 2008.  We paid the fourth installment on March 31, 2011, and as of September 30, 2011, the net present value of the note (representing the outstanding balance included as debt on our accompanying consolidated balance sheet) was $9.7 million.  As of December 31, 2010, the net present value of the note was $19.2 million.
 
Kinder Morgan Texas Pipeline, L.P. Debt
 
Our subsidiary, Kinder Morgan Texas Pipeline, L.P. is the obligor on a series of unsecured senior notes, which were assumed on August 1, 2005 when we acquired a natural gas storage facility located in Liberty County, Texas from a third party.  The notes have a fixed annual stated interest rate of 8.85%; however, we valued the debt equal to the present value of amounts to be paid determined using an approximate interest rate of 5.23%.  The assumed principal amount, along with interest, is due in monthly installments of approximately $0.7 million, and the final payment is due January 2, 2014.  During the first nine months of 2011, we paid a combined principal amount of $5.4 million, and as of September 30, 2011, Kinder Morgan Texas Pipeline L.P.’s outstanding balance under the senior notes was $18.2 million.  Additionally, the unsecured senior notes may be prepaid at any time in amounts of at least $1.0 million and at a price equal to the higher of par value or the present value of the remaining scheduled payments of principal and interest on the portion being prepaid. As of December 31, 2010, the outstanding balance under the notes was $23.6 million.
 
Kinder Morgan Arrow Terminals, L.P. Debt
 
On April 4, 2011, our subsidiary Kinder Morgan Arrow Terminals, L.P. acquired a parcel of land and a terminal warehouse located in Industry, Pennsylvania from a third party for an aggregate consideration of $3.3 million, consisting of $1.2 million in cash and a $2.1 million promissory note payable.  The note principal is payable in three annual payments beginning in March 2012.  The note bears interest at 6% per annum, and accrued interest on the unpaid principal amount is due and payable on the due date of each principal installment.
 
KinderHawk Field Services LLC Credit Facility
 
On July 1, 2011, immediately following our acquisition of KinderHawk Field Services LLC (discussed in Note 2), we repaid the outstanding $154.0 million of borrowings under KinderHawk’s revolving bank credit facility and following this repayment, KinderHawk had no outstanding debt.  The revolving bank credit facility was terminated at the time of such repayment.
 
Interest Rate Swaps
 
Information on our interest rate swaps is contained in Note 6 “Risk Management—Interest Rate Risk Management.”
 
Contingent Debt
 
Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote.  As of September 30, 2011, our contingent debt obligations, as well as our obligations with respect to related letters of credit, consisted of the following two items:
 
 
an aggregate $80.7 million for our contingent share (50%) of Cortez Pipeline Company’s debt obligations, consisting of (i) $70.0 million for our contingent share of outstanding borrowings under Cortez’s debt facilities (described below); and (ii) $10.7 million for a letter of credit issued on our behalf to secure our indemnification obligations to Shell for 50% of the $21.4 million in principal amount of Cortez’s Series D notes outstanding as of that date.  Cortez Pipeline Company is a Texas general partnership that owns and operates a common carrier carbon dioxide pipeline system.
 
 
 
We are severally liable for our percentage ownership share (50%) of Cortez’s debt, and as of September 30, 2011, Cortez’s debt facilities consisted of (i) $21.4 million aggregate principal amount of Series D notes due May 15, 2013 (interest on the Series D notes is paid annually and based on a fixed interest rate of 7.14% per annum); (ii) $100.0 million of variable rate Series E notes due December 11, 2012 (interest on the Series E notes is paid quarterly and based on an interest rate of three-month LIBOR plus a spread); and (iii) $18.5 million of outstanding borrowings under a $40.0 million committed revolving bank credit facility that is also due December 11, 2012.  Accordingly, as of September 30, 2011, our contingent share of Cortez’s debt was $70.0 million (50% of total borrowings).
 
 
 
With respect to the Series D notes, Shell Oil Company shares our several guaranty obligations jointly and severally; however, we are obligated to indemnify Shell for the liabilities it incurs in connection with such guaranty.  Accordingly, as of September 30, 2011, we have a letter of credit in the amount of $10.7 million issued by JPMorgan Chase Bank, in order to secure our indemnification obligations to Shell for 50% of the $21.4 million in principal amount of Series D notes outstanding as of that date.
 
 
 
Further, pursuant to a Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company are required to contribute capital to Cortez in the event of a cash deficiency.  The agreement contractually supports the financings of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company, by obligating the partners of Cortez Pipeline to fund cash deficiencies at Cortez Pipeline, including anticipated deficiencies and cash deficiencies relating to the repayment of principal and interest on the debt of Cortez Capital Corporation.  The partners’ respective parent or other companies further severally guarantee the obligations of the Cortez Pipeline owners under this agreement; and
 
 
an $18.3 million letter of credit posted as security for borrowings under Adjustable Demand Revenue Bonds issued by the Nassau County, Florida Ocean Highway and Port Authority.  The bonds were issued for the purpose of constructing certain port improvements located in Fernandino Beach, Nassau County, Florida.  Our subsidiary, Nassau Terminals LLC is the operator of the marine port facilities.  The bond indenture is for 30 years and allows the bonds to remain outstanding until December 1, 2020.  Principal payments on the bonds are made on the first of December each year, and corresponding reductions are made to the letter of credit.  As of September 30, 2011, this letter of credit had a face amount of $18.3 million.
 
On February 25, 2011, Midcontinent Express Pipeline LLC entered into a three-year $75.0 million unsecured revolving bank credit facility that is due February 25, 2014.  This credit facility replaced Midcontinent Express’ previous $175.4 million credit facility that was terminated on February 28, 2011, and on this same date, each of its two member owners, including us, were released from their respective debt obligations under the previous guaranty agreements.  Accordingly, we no longer have a contingent debt obligation with respect to Midcontinent Express Pipeline LLC.
 
On July 28, 2011, Fayetteville Express Pipeline LLC entered into (i) a new unsecured $600.0 million term loan that is due on July 28, 2012, with the ability to extend one additional year; and (ii) a $50.0 million unsecured revolving bank credit facility that is due on July 28, 2015.  These debt instruments replaced Fayetteville Express’ $1.1 billion credit facility that was terminated on July 28, 2011, and on this same date, each of its two member owners, including us, were released from their respective debt obligations under the previous guaranty agreements.  Accordingly, we no longer have a contingent debt obligation with respect to Fayetteville Express Pipeline LLC. 
 
For additional information regarding our debt facilities and our contingent debt agreements, see Note 8 “Debt” and Note 12 “Commitments and Contingent Liabilities” to our consolidated financial statements included in our 2010 Form 10-K/A.
 
 
5.  Partners’ Capital
 
Limited Partner Units
 
As of September 30, 2011 and December 31, 2010, our partners’ capital included the following limited partner units:
 
   
September 30,
   
December 31,
 
   
2011
   
2010
 
Common units
    230,843,095       218,880,103  
Class B units
    5,313,400       5,313,400  
i-units
    96,807,608       91,907,987  
Total limited partner units
    332,964,103       316,101,490  
 
The total limited partner units represent our limited partners’ interest and an effective 98% interest in us, exclusive of our general partner’s incentive distribution rights.  Our general partner has an effective 2% interest in us, excluding its right to receive incentive distributions.
 
As of September 30, 2011, our total common units consisted of 214,472,667 units held by third parties, 14,646,428 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner.  As of December 31, 2010, our total common units consisted of 202,509,675 units held by third parties, 14,646,428 units held by KMI and its consolidated affiliates (excluding our general partner), and 1,724,000 units held by our general partner.
 
As of both September 30, 2011 and December 31, 2010, all of our 5,313,400 Class B units were held by a wholly-owned subsidiary of KMI.  The Class B units are similar to our common units except that they are not eligible for trading on the New York Stock Exchange.
 
As of both September 30, 2011 and December 31, 2010, all of our i-units were held by KMR.  Our i-units are a separate class of limited partner interests in us and are not publicly traded.  The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units.  When cash is paid to the holders of our common units, we issue additional i-units to KMR.  The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units.
 

 

 

 

 

 

 

 
Changes in Partners’ Capital
 
For each of the three and nine month periods ended September 30, 2011 and 2010, changes in the carrying amounts of our Partners’ Capital attributable to both us and our noncontrolling interests, including our comprehensive income are summarized as follows (in millions):
 
   
Three Months Ended September 30,
 
   
2011
   
2010
 
   
KMP
   
Noncontrolling
Interests
   
Total
   
KMP
   
Noncontrolling interests
   
Total
 
                                     
Beginning Balance
  $ 7,616.2     $ 87.7     $ 7,703.9     $ 7,023.1     $ 83.1     $ 7,106.2  
                                                 
Units issued for cash
    107.5       -       107.5       203.5       -       203.5  
Distributions paid in cash
    (566.5 )     (7.0 )     (573.5 )     (333.7 )     (4.7 )     (338.4 )
Noncash compensation expense allocated from KMI(a)
    -       -       -       1.0       -       1.0  
Cash contributions
    -       2.3       2.3       -       3.0       3.0  
Other adjustments
    (4.1 )     -       (4.1 )     (0.2 )     -       (0.2 )
                                                 
Comprehensive income:
                                               
Net Income
    214.5       1.8       216.3       320.8       1.6       322.4  
Other comprehensive income:
                                               
Change in fair value of derivatives utilized for hedging purposes
    382.7       3.9       386.6       (82.5 )     (0.8 )     (83.3 )
Reclassification of change in fair value of derivatives to  net income
    48.5       0.5       49.0       47.2       0.4       47.6  
Foreign currency translation adjustments
    (161.8 )     (1.7 )     (163.5 )     62.2       0.7       62.9  
Adjustments to pension and other postretirement benefit plan liabilities
    -       -       -       0.3       -       0.3  
Total other comprehensive income
    269.4       2.7       272.1       27.2       0.3       27.5  
Comprehensive income
    483.9       4.5       488.4       348.0       1.9       349.9  
                                                 
Ending Balance
  $ 7,637.0     $ 87.5     $ 7,724.5     $ 7,241.7     $ 83.3     $ 7,325.0  
__________

























   
Nine Months Ended September 30,
 
   
2011
   
2010
 
   
KMP
   
Noncontrolling
Interests
   
Total
   
KMP
   
Noncontrolling interests
   
Total
 
                                     
Beginning Balance
  $ 7,210.7     $ 81.8     $ 7,292.5     $ 6,644.5     $ 79.6     $ 6,724.1  
                                                 
Units issued as consideration pursuant to common unit compensation plan for non-employee directors
    0.2       -       0.2       0.2       -       0.2  
Units issued as consideration in the acquisition of assets
    23.7       -       23.7       81.7       -       81.7  
Units issued for cash
    813.3       -       813.3       636.6       -       636.6  
Distributions paid in cash
    (1,638.8 )     (20.5 )     (1,659.3 )     (1,282.7 )     (16.7 )     (1,299.4 )
Noncash compensation expense allocated from KMI(a)
    89.0       0.9       89.9       3.7       -       3.7  
Cash contributions
    -        15.4       15.4       -       10.2       10.2  
Other adjustments
    (2.9 )     -       (2.9 )     (0.2 )     -       (0.2 )
                                                 
Comprehensive income:
                                               
Net Income
    782.8       6.3       789.1       907.3       7.6       914.9  
Other comprehensive income:
                                               
Change in fair value of derivatives utilized for hedging purposes
    285.9       2.9       288.8       83.5       0.9       84.4  
Reclassification of change in fair value of derivatives to  net income
    186.9       1.9       188.8       133.3       1.3       134.6  
Foreign currency translation adjustments
    (100.8 )     (1.0 )     (101.8 )     35.9       0.4       36.3  
Adjustments to pension and other postretirement benefit plan liabilities
    (13.0 )     (0.2 )     (13.2 )     (2.1 )     -       (2.1 )
Total other comprehensive income
    359.0       3.6       362.6       250.6       2.6       253.2  
Comprehensive income
    1,141.8       9.9       1,151.7       1,157.9       10.2       1,168.1  
                                                 
Ending Balance
  $ 7,637.0     $ 87.5     $ 7,724.5     $ 7,241.7     $ 83.3     $ 7,325.0  
____________
 
(a)
For further information about this expense, see Note 9.  We do not have any obligation, nor do we expect to pay any amounts related to this expense.

 
During the first nine months of both 2011 and 2010, there were no material changes in our ownership interests in subsidiaries in which we retained a controlling financial interest.
 
Equity Issuances
 
On February 25, 2011, we entered into a second amended and restated equity distribution agreement with UBS Securities LLC to provide for the offer and sale of common units having an aggregate offering price of up to $1.2 billion (up from an aggregate offering price of up to $600 million under our first amended and restated agreement) from time to time through UBS, as our sales agent.  During the three and nine months ended September 30, 2011, we issued 1,553,285 and 3,930,581, respectively, of our common units pursuant to this equity distribution agreement.  After commissions of $0.9 million and $2.2 million, respectively, we received net proceeds of $107.5 million and $279.4 million, respectively, from the issuance of these common units.  We used the proceeds to reduce the borrowings under our commercial paper program.  For additional information regarding our equity distribution agreement, see Note 10 to our consolidated financial statements included in our 2010 Form 10-K/A.
 
On June 10, 2011, we issued 324,961 common units as part of our purchase price for the petroleum coke terminal assets we acquired from TGS Development, L.P.  We valued the common units at $23.7 million, determining the units’ value based on the $73.01 closing market price of the common units on the New York Stock Exchange on the June 10, 2011 acquisition date.  For more information on this acquisition, see Note 2.
 

 
On June 17, 2011, we issued, in a public offering, 6,700,000 of our common units at a price of $71.44 per unit, less commissions and underwriting expenses.  At the time of the offering, we granted the underwriters a 30-day option to purchase up to an additional 1,005,000 common units from us on the same terms and conditions, and upon the underwriters’ exercise of this option in full, we issued the additional 1,005,000 common units on June 27, 2011.  We received net proceeds, after deducting the underwriter discount, of $533.9 million from the issuance of these 7,705,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.
 
Equity Issuances Subsequent to September 30, 2011
 
In October 2011, we issued 58,092 of our common units for the settlement of sales made on or before September 30, 2011 pursuant to our equity distribution agreement.  We received net proceeds of $4.0 million for the issuance of these 58,092 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.
 
Income Allocation and Declared Distributions
 
For the purposes of maintaining partner capital accounts, our partnership agreement specifies that items of income and loss shall be allocated among the partners, other than owners of i-units, in accordance with their percentage interests.  Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to our general partner.  Incentive distributions are generally defined as all cash distributions paid to our general partner that are in excess of 2% of the aggregate value of cash and i-units being distributed, and we determine the allocation of incentive distributions to our general partner by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of our partnership agreement.
 
On August 12, 2011, we paid a cash distribution of $1.15 per unit to our common unitholders and to our Class B unitholder for the quarterly period ended June 30, 2011.  KMR, our sole i-unitholder, received a distribution of 1,701,916 i-units from us on August 12, 2011, based on the $1.15 per unit distributed to our common unitholders on that date.  The distributions were declared on July 20, 2011, payable to unitholders of record as of August 1, 2011.
 
On August 13, 2010, we paid a cash distribution of $1.09 per unit to our common unitholders and our Class B unitholders for the quarterly period ended June 30, 2010.  KMR, our sole i-unitholder, received a distribution of 1,625,869 i-units from us on August 13, 2010, based on the $1.09 per unit distributed to our common unitholders on that date.  The distributions were declared on July 21, 2010, payable to unitholders of record as of July 30, 2010.
 
Our August 12, 2011 incentive distribution payment to our general partner for the quarterly period ended June 30, 2011 totaled $292.8 million; however, this incentive distribution was affected by a waived incentive distribution amount equal to $7.1 million related to common units issued to finance a portion of our May 2010 acquisition of a 50% ownership interest in KinderHawk Field Services LLC.  Beginning with our distribution payments for the quarterly period ended June 30, 2010 (discussed following), our general partner has agreed not to take incentive distributions related to this joint venture acquisition through year-end 2011.
 
On August 13, 2010, we paid an incentive distribution to our general partner for the second quarter of 2010 totaling $89.8 million.  Based on a limited partner distribution of $1.09 per unit to our common unitholders, our general partner would expect to receive an incentive distribution in the amount of $263.4 million; however, this incentive distribution was reduced by a combined $173.6 million, including (i) a waived incentive amount equal to $5.3 million related to our May 2010 KinderHawk acquisition; and (ii)a reduced incentive amount equal to $168.3 million due to a portion of our available cash distribution for the second quarter of 2010 being a distribution of cash from interim capital transactions, rather than a distribution of cash from operations (including the general partner’s 2% general partner interest, its total cash distributions were reduced by $170.0 million).  
 
Our distribution of cash for the second quarter of 2010 (which we paid in the third quarter of 2010) from interim capital transactions totaled $177.1 million (approximately $0.56 per limited partner unit), and pursuant to the provisions of our partnership agreement, our general partner receives no incentive distribution on distributions of cash from interim capital transactions; accordingly, this distribution from interim capital transactions helped preserve our cumulative excess cash coverage.  In the first nine months of 2011 and 2010, we made incentive distribution payments to our general partner totaling $847.4 million and $581.5 million, respectively.
 

 
Subsequent Event
 
On October 19, 2011, we declared a cash distribution of $1.16 per unit for the quarterly period ended September 30, 2011.  The distribution will be paid on November 14, 2011, to unitholders of record as of October 31, 2011.  Our common unitholders and our Class B unitholder will receive cash.  KMR will receive a distribution of 1,701,781 additional i-units based on the $1.16 distribution per common unit.  For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.017579) will be issued.  This fraction was determined by dividing:
 
▪     $1.16, the cash amount distributed per common unit
 
by
 
 
$65.986, the average of KMR’s shares’ closing market prices from October 13-26, 2011, the ten consecutive trading days preceding the date on which the shares began to trade ex-dividend under the rules of the New York Stock Exchange.
 
Our declared distribution for the third quarter of 2011 of $1.16 per unit will result in an incentive distribution to our general partner of $299.0 million (including the effect of a waived incentive distribution amount of $7.2 million related to our May 2010 KinderHawk acquisition).  Comparatively, our distribution of $1.11 per unit paid on November 12, 2010 for the third quarter of 2010 resulted in an incentive distribution payment to our general partner in the amount of $266.7 million.  The increased incentive distribution to our general partner for the third quarter of 2011 over the incentive distribution for the third quarter of 2010 reflects the increase in the amount distributed per unit as well as the issuance of additional units.  For additional information about our 2010 partnership distributions, see Notes 10 and 11 to our consolidated financial statements included in our 2010 Form 10-K/A.
 
 
6.  Risk Management
 
Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, natural gas liquids and crude oil.  We also have exposure to interest rate risk as a result of the issuance of our debt obligations.  Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to certain of these risks.
 
Energy Commodity Price Risk Management
 
We are exposed to risks associated with changes in the market price of natural gas, natural gas liquids and crude oil as a result of the forecasted purchase or sale of these products.  Specifically, these risks are primarily associated with price volatility related to (i) pre-existing or anticipated physical natural gas, natural gas liquids and crude oil sales; (ii) natural gas purchases; and (iii) natural gas system use and storage.  Price changes are often caused by shifts in the supply and demand for these commodities, as well as their locations.
 
Our principal use of energy commodity derivative contracts is to mitigate the risk associated with unfavorable market movements in the price of energy commodities.  Our energy commodity derivative contracts act as a hedging (offset) mechanism against the volatility of energy commodity prices by allowing us to transfer this price risk to counterparties who are able and willing to bear it.
 
For derivative contracts that are designated and qualify as cash flow hedges pursuant to U.S. generally accepted accounting principles, the portion of the gain or loss on the derivative contract that is effective (as defined by U.S. generally accepted accounting principles) in offsetting the variable cash flows associated with the hedged forecasted transaction is reported as a component of other comprehensive income and reclassified into earnings in the same line item associated with the forecasted transaction and in the same period or periods during which the hedged transaction affects earnings (e.g., in “revenues” when the hedged transactions are commodity sales).  The remaining gain or loss on the derivative contract in excess of the cumulative change in the present value of future cash flows of the hedged item, if any (i.e., the ineffective portion as defined by U.S. generally accepted accounting principles), is recognized in earnings during the current period.
 
The effectiveness of hedges using an option contract may be assessed based on changes in the option’s intrinsic value with the change in the time value of the contract being excluded from the assessment of hedge effectiveness.  Changes in the excluded component of the change in an option’s time value are included currently in earnings.  During the three and nine months ended September 30, 2011, we recognized net gains of $8.5 million and $10.4 million, respectively, related to crude oil hedges and resulting from both hedge ineffectiveness and amounts excluded from effectiveness testing.  During the three and nine months ended September 30, 2010, we recognized net losses of $9.5 million and net gains of $4.6 million, respectively, related to crude oil and natural gas hedges and resulting from both hedge ineffectiveness and amounts excluded from effectiveness testing.
 
Additionally, during the three and nine months ended September 30, 2011, we reclassified losses of $49.0 million and $188.8 million, respectively, from “Accumulated other comprehensive loss” into earnings, and for the same comparable periods last year, we reclassified losses of $47.6 million and $134.6 million, respectively, into earnings.  No material amounts were reclassified into earnings as a result of the discontinuance of cash flow hedges because it was probable that the original forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather, the amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchase actually occurred).  The proceeds or payments resulting from the settlement of our cash flow hedges are reflected in the operating section of our statement of cash flows as changes to net income and working capital.
 
The “Accumulated other comprehensive gain” balance included in our Partners’ Capital (exclusive of the portion included in “Noncontrolling interests”) was $172.6 million as of September 30, 2011.  As of December 31, 2010, we had an “Accumulated other comprehensive loss” balance of $186.4 million.  These totals included a $165.1 million gain amount and a $307.1 million loss amount, respectively, associated with energy commodity price risk management activities.  Approximately $56.7 million of the total gain amount associated with energy commodity price risk management activities and included in our Partners’ Capital as of September 30, 2011 is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur), however, actual amounts could vary materially as a result of changes in market prices.  As of September 30, 2011, the maximum length of time over which we have hedged our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2015.
 
As of September 30, 2011, we had entered into the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:
 
 
Net open position
long/(short)
Derivatives designated as hedging contracts
 
Crude oil
       (21.8) million barrels
Natural gas fixed price
         (3.6) billion cubic feet
Natural gas basis
         (4.2) billion cubic feet
Derivatives not designated as hedging contracts
 
Natural gas fixed price
          0.2 billion cubic feet
Natural gas basis
          2.3 billion cubic feet

For derivative contracts that are not designated as a hedge for accounting purposes, all realized and unrealized gains and losses are recognized in the statement of income during the current period.  These types of transactions include basis spreads, basis-only positions and gas daily swap positions.  We primarily enter into these positions to economically hedge an exposure through a relationship that does not qualify for hedge accounting.  Until settlement occurs, this will result in non-cash gains or losses being reported in our operating results.
 
Interest Rate Risk Management
 
In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt.  We use interest rate swap agreements to manage the interest rate risk associated with the fair value of our fixed rate borrowings and to effectively convert a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate cash flows in order to achieve our desired mix of fixed and variable rate debt.
 
Since the fair value of fixed rate debt varies inversely with changes in the market rate of interest, we enter into swap agreements to receive a fixed and pay a variable rate of interest in order to convert the interest expense associated with certain of our senior notes from fixed rates to variable rates, resulting in future cash flows that vary with the market rate of interest.  These swaps, therefore, hedge against changes in the fair value of our fixed rate debt that result from market interest rate changes.  For derivative contracts that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings.
 
As of September 30, 2011, we had a combined notional principal amount of $5,325 million of fixed-to-variable interest rate swap agreements, effectively converting the interest expense associated with certain series of our senior notes from fixed rates to variable rates based on an interest rate of LIBOR plus a spread.  All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of September 30, 2011, the maximum length of time over which we have hedged a portion of our exposure to the variability in the value of this debt due to interest rate risk is through March 15, 2035.
 
As of December 31, 2010, we had a combined notional principal amount of $4,775 million of fixed-to-variable interest rate swap agreements.  In March 2011, we entered into four additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $500 million.  Each agreement effectively converts a portion of the interest expense associated with our 3.50% senior notes due March 1, 2016 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.
 
In August 2011, we entered into two additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $250 million, effectively converting a portion of the interest expense associated with our 4.15% senior notes due March 1, 2022 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.  We also terminated two existing fixed-to-variable swap agreements having a combined notional principal amount of $200 million in two separate transactions.  We received combined proceeds of $73.0 million from the early termination of these swap agreements.
 
Fair Value of Derivative Contracts
 
The fair values of our current and non-current asset and liability derivative contracts are each reported separately as “Fair value of derivative contracts” on our accompanying consolidated balance sheets.  The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets as of September 30, 2011 and December 31, 2010 (in millions):
 
Fair Value of Derivative Contracts
 
               
     
Asset derivatives
   
Liability derivatives
 
     
September 30,
   
December 31,
   
September 30,
   
December 31,
 
     
2011
   
2010
   
2011
   
2010
 
 
Balance sheet location
 
Fair value
   
Fair value
   
Fair value
   
Fair value
 
Derivatives designated as hedging contracts
                         
Energy commodity derivative contracts
Current
  $ 123.7     $ 20.1     $ (67.0 )   $ (275.9 )
 
Non-current
    133.0       43.1       (21.4 )     (103.0 )
Subtotal
      256.7       63.2       (88.4 )     (378.9 )
                                   
Interest rate swap agreements
Current
    6.1       -       -       -  
 
Non-current
    570.4       217.6       -       (69.2 )
Subtotal
      576.5       217.6       -       (69.2 )
                                   
Total
      833.2       280.8       (88.4 )     (448.1 )
                                   
Derivatives not designated as hedging contracts
                                 
Energy commodity derivative contracts
Current
    5.4       3.9       (4.9 )     (5.6 )
Total
      5.4       3.9       (4.9 )     (5.6 )
                                   
Total derivatives
    $ 838.6     $ 284.7     $ (93.3 )   $ (453.7 )
____________
 
The offsetting entry to adjust the carrying value of the debt securities whose fair value was being hedged is included within “Value of interest rate swaps” on our accompanying consolidated balance sheets, which also includes any unamortized portion of proceeds received from the early termination of interest rate swap agreements.  As of September 30, 2011 and December 31, 2010, this unamortized premium totaled $494.7 million and $456.5 million, respectively, and as of September 30, 2011, the weighted average amortization period for this premium was approximately 17.9 years.
 
Effect of Derivative Contracts on the Income Statement
 
The following three tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the three and nine months ended September 30, 2011 and 2010 (in millions):
 
Derivatives in fair value hedging relationships
Location of gain/(loss) recognized in income on derivative
 
Amount of gain/(loss) recognized in income
on derivative(a)
 
     
Three Months Ended
   
Nine Months Ended
 
     
September 30,
   
September 30,
 
     
2011
   
2010
   
2011
   
2010
 
Interest rate swap agreements
Interest, net - income/(expense)
  $ 436.8     $ 219.9     $ 501.1     $ 634.1  
Total
    $ 436.8     $ 219.9     $ 501.1     $ 634.1  

Hedged items in fair value hedging relationships
Location of gain/(loss) recognized in income on related hedged item
 
Amount of gain/(loss) recognized in income
on related hedged item(a)
 
     
Three Months Ended
   
Nine Months Ended
 
     
September 30,
   
September 30,
 
     
2011
   
2010
   
2011
   
2010
 
Fixed rate debt
Interest, net - income/(expense)
  $ (436.8 )   $ (219.9 )   $ (501.1 )   $ (634.1 )
Total
    $ (436.8 )   $ (219.9 )   $ (501.1 )   $ (634.1 )
____________
 
(a)
Amounts reflect the change in the fair value of interest rate swap agreements and the change in the fair value of the associated fixed rate debt which exactly offset each other as a result of no hedge ineffectiveness.
 
____________
 

Derivatives in cash flow hedging relationships
 
Amount of gain/(loss) recognized in OCI on derivative (effective portion)
 
Location of gain/(loss) recognized from Accumulated OCI into income (effective portion)
 
Amount of gain/(loss) reclassified from Accumulated OCI into income (effective portion)
 
Location of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
 
Amount of gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
 

 
Three Months Ended
   
Three Months Ended
   
Three Months Ended
 
 
September 30,
   
September 30,
   
September 30,
 
 
2011
 
2010
   
2011
 
2010
   
2011
 
2010
 
Energy commodity
 derivative contracts
  $ 386.6     $ (83.3 )
Revenues–natural
 gas sales
  $ -     $ 3.6  
Revenues–natural
 gas sales
  $ -     $ -  
                 
Revenues–product
 sales and other
    (50.5 )     (44.2 )
Revenues–product
 sales and other
    8.5       (7.9 )
                 
Gas purchases and
 other costs of sales
    1.5       (7.0 )
Gas purchases and
 other costs of sales
    -       (1.6 )
Total
  $ 386.6     $ (83.3 )
Total
  $ (49.0 )   $ (47.6 )
Total
  $ 8.5     $ (9.5 )
                                                     

 
Nine Months Ended
   
Nine Months Ended
   
Nine Months Ended
 
 
September 30,
   
September 30,
   
September 30,
 
 
2011
 
2010
   
2011
 
2010
   
2011
 
2010
 
Energy commodity
 derivative contracts
  $ 288.8     $ 84.4  
Revenues–natural
 gas sales
  $ 1.0     $ 5.3  
Revenues–natural
 gas sales
  $ -     $ -  
                 
Revenues–product
 sales and other
    (202.7 )     (142.6 )
Revenues–product
 sales and other
    10.4       5.4  
                 
Gas purchases and
 other costs of sales
    12.9       2.7  
Gas purchases and
 other costs of sales
    -       (0.8 )
Total
  $ 288.8     $ 84.4  
Total
  $ (188.8 )   $ (134.6 )
Total
  $ 10.4     $ 4.6  
____________
 

 

 
Derivatives not designated
as hedging contracts
Location of gain/(loss) recognized
in income on derivative
 
Amount of gain/(loss) recognized
in income on derivative
 
     
Three Months Ended
   
Nine Months Ended
 
     
September 30,
   
September 30,
 
     
2011
   
2010
   
2011
   
2010
 
Energy commodity derivative contracts
Gas purchases and other costs of sales
  $ (0.1 )   $ 0.2     $ 0.1     $ 1.0  
Total
    $ (0.1 )   $ 0.2     $ 0.1     $ 1.0  
____________

Credit Risks
 
We have counterparty credit risk as a result of our use of financial derivative contracts.  Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies.  This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
 
We maintain credit policies with regard to our counterparties that we believe minimize our overall credit risk.  These policies include (i) an evaluation of potential counterparties’ financial condition (including credit ratings); (ii) collateral requirements under certain circumstances; and (iii) the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty.  Based on our policies, exposure, credit and other reserves, our management does not anticipate a material adverse effect on our financial position, results of operations, or cash flows as a result of counterparty performance.
 
Our over-the-counter swaps and options are entered into with counterparties outside central trading organizations such as futures, options or stock exchanges.  These contracts are with a number of parties, all of which have investment grade credit ratings.  While we enter into derivative transactions principally with investment grade counterparties and actively monitor their ratings, it is nevertheless possible that from time to time losses will result from counterparty credit risk in the future.
 
The maximum potential exposure to credit losses on our derivative contracts as of September 30, 2011 was (in millions):
 
   
Asset position
 
Interest rate swap agreements
  $ 576.5  
Energy commodity derivative contracts
    262.1  
Gross exposure
    838.6  
Netting agreement impact
    (78.5 )
Net exposure
  $ 760.1  

In conjunction with the purchase of exchange-traded derivative contracts or when the market value of our derivative contracts with specific counterparties exceeds established limits, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts.  As of both September 30, 2011 and December 31, 2010, we had no outstanding letters of credit supporting our hedging of energy commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil.
 
As of September 30, 2011 and December 31, 2010, our counterparties associated with our energy commodity contract positions and over-the-counter swap agreements had margin deposits with us totaling $8.9 million and $2.4 million, respectively, and we reported these amounts within “Accrued other current liabilities” in our accompanying consolidated balance sheets.  We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring us to post additional collateral upon a decrease in our credit rating.  Based on contractual provisions as of September 30, 2011, we estimate that if our credit rating was downgraded, we would have the following additional collateral obligations (in millions):
 

 
Credit ratings downgraded (a)
 
Incremental obligations
   
Cumulative obligations(b)
 
One notch to BBB-/Baa3
  $ -     $ -  
                 
Two notches to below BBB-/Baa3 (below investment grade)
  $ 12.8     $ 12.8  
_________

 (a)
If there are split ratings among the independent credit rating agencies, most counterparties use the higher credit rating to determine our incremental collateral obligations, while the remaining use the lower credit rating.  Therefore, a two notch downgrade to below BBB-/Baa3 by one agency would not trigger the entire $12.8 million incremental obligation.
 
(b)
Includes current posting at current rating.
 
 
7.  Fair Value
 
The Codification emphasizes that fair value is a market-based measurement that should be determined based on assumptions (inputs) that market participants would use in pricing an asset or liability.  Inputs may be observable or unobservable, and valuation techniques used to measure fair value should maximize the use of relevant observable inputs and minimize the use of unobservable inputs. Accordingly, the Codification establishes a hierarchal disclosure framework that ranks the quality and reliability of information used to determine fair values.  The hierarchy is associated with the level of pricing observability utilized in measuring fair value and defines three levels of inputs to the fair value measurement process—quoted prices are the most reliable valuation inputs, whereas model values that include inputs based on unobservable data are the least reliable.  Each fair value measurement must be assigned to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety.
 
The three broad levels of inputs defined by the fair value hierarchy are as follows:
 
 
Level 1 Inputs—quoted prices (unadjusted) in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date;
 
 
Level 2 Inputs—inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly.  If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability; and
 
 
Level 3 Inputs—unobservable inputs for the asset or liability.  These unobservable inputs reflect the entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability, and are developed based on the best information available in the circumstances (which might include the reporting entity’s own data).
 
Fair Value of Derivative Contracts
 
The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; and (ii) interest rate swap agreements as of September 30, 2011 and December 31, 2010, based on the three levels established by the Codification (in millions).  The fair value measurements in the tables below do not include cash margin deposits made by us or our counterparties, which would be reported within “Restricted deposits” and “Accrued other liabilities,” respectively, in our accompanying consolidated balance sheets.
 

 

 

 

 

 

 
   
Asset fair value measurements using
 
   
Total
   
Quoted prices in
active markets
for identical
assets (Level 1)
   
Significant other
observable
inputs (Level 2)
   
Significant
unobservable
inputs (Level 3)
 
As of September 30, 2011
                       
Energy commodity derivative contracts(a)
  $ 262.1     $ 25.3     $ 172.2     $ 64.6  
Interest rate swap agreements
  $ 576.5     $ -     $ 576.5     $ -  
                                 
As of December 31, 2010
                               
Energy commodity derivative contracts(a)
  $ 67.1     $ -     $ 23.5     $ 43.6  
Interest rate swap agreements
  $ 217.6     $ -     $ 217.6     $ -  
____________
 
   
Liability fair value measurements using
 
   
Total
   
Quoted prices in
active markets
for identical
liabilities
(Level 1)
   
Significant other
observable
inputs (Level 2)
   
Significant
unobservable
inputs (Level 3)
 
As of September 30, 2011
                       
Energy commodity derivative contracts(a)
  $ (93.3 )   $ (12.6 )   $ (60.7 )   $ (20.0 )
Interest rate swap agreements
  $ -     $ -     $ -     $ -  
                                 
As of December 31, 2010
                               
Energy commodity derivative contracts(a)
  $ (384.5 )   $ -     $ (359.7 )   $ (24.8 )
Interest rate swap agreements
  $ (69.2 )   $ -     $ (69.2 )   $ -  
____________
 
(a)
Level 1 consists primarily of NYMEX natural gas futures.  Level 2 consists primarily of OTC West Texas Intermediate swaps and OTC natural gas swaps that are settled on NYMEX.  Level 3 consists primarily of natural gas basis swaps and West Texas Intermediate options.
 
 
The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the three and nine months ended September 30, 2011 and 2010 (in millions):
 
Significant unobservable inputs (Level 3)
 
                         
   
Three Months Ended
September 30,
   
Nine Months Ended
September 30,
 
   
2011
   
2010
   
2011
   
2010
 
Derivatives-net asset (liability)
                       
Beginning of Period
  $ 6.7     $ 46.6     $ 18.8     $ 13.0  
Transfers into Level 3
    -       -       -       -  
Transfers out of Level 3
    -       -       -       -  
Total gains or (losses):
                               
     Included in earnings
    2.6       (7.5 )     5.4       3.6  
     Included in other comprehensive income
    37.0       (3.9 )     21.5