10-Q 1 form10q_1q2011.htm KMP 10Q 1Q 2011 form10q_1q2011.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 March 31, 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 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 Securities Exchange Act of 1934.  Large accelerated filer [X]     Accelerated filer [   ]  Non-accelerated filer [   ]  Smaller reporting company [   ]
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934).  Yes [   ]  No [X]
 
The Registrant had 220,127,449 common units outstanding as of April 29, 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 Months Ended March 31, 2011 and 2010
 
Consolidated Balance Sheets – March 31, 2011 and December 31, 2010                                                                                                                       
 
Consolidated Statements of Cash Flows – Three Months Ended March 31, 2011 and 2010
 
Notes to Consolidated Financial Statements                                                                                                                       
     
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
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                                                                                                                            
58
     
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds                                                                                                                            
58
     
Item 3.
Defaults Upon Senior Securities
58
     
Item 4.
(Removed and Reserved)                                                                                                                            
58
     
Item 5.
Other Information                                                                                                                            
58
     
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
March 31,
 
   
2011
   
2010
 
Revenues
           
Natural gas sales
  $ 806.0     $ 1,017.5  
Services
    784.4       738.5  
Product sales and other
    402.4       373.6  
Total Revenues
    1,992.8       2,129.6  
                 
Operating Costs, Expenses and Other
               
Gas purchases and other costs of sales
    815.7       1,016.6  
Operations and maintenance
    308.6       452.9  
Depreciation, depletion and amortization
    221.8       227.3  
General and administrative
    189.2       101.1  
Taxes, other than income taxes
    48.6       45.1  
Other expense (income)
    (0.2 )     (1.3 )
Total Operating Costs, Expenses and Other
    1,583.7       1,841.7  
                 
Operating Income
    409.1       287.9  
                 
Other Income (Expense)
               
Earnings from equity investments
    64.9       46.7  
Amortization of excess cost of equity investments
    (1.5 )     (1.4 )
Interest expense
    (132.0 )     (117.0 )
Interest income
    5.3       5.5  
Other, net
    1.6       6.7  
Total Other Income (Expense)
    (61.7 )     (59.5 )
                 
Income Before Income Taxes
    347.4       228.4  
                 
Income Taxes
    (6.5 )     (1.0 )
                 
Net Income
    340.9       227.4  
                 
Net Income Attributable to Noncontrolling Interests
    (3.1 )     (2.1 )
                 
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
  $ 337.8     $ 225.3  
                 
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.
  $ 337.8     $ 225.3  
Less: General Partner’s interest
    (280.6 )     (249.2 )
Limited Partners’ Interest in Net Income (Loss)
  $ 57.2     $ (23.9 )
                 
Limited Partners’ Net Income (Loss) per Unit
  $ 0.18     $ (0.08 )
                 
Weighted Average Number of Units Used in Computation of Limited
Partners’ Net Income (Loss) per Unit
    317.2       298.8  
                 
Per Unit Cash Distribution Declared
  $ 1.14     $ 1.07  

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



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

   
March 31,
2011
   
December 31, 2010
 
   
(Unaudited)
       
ASSETS
           
Current assets
           
Cash and cash equivalents
  $ 178.4     $ 129.1  
Restricted deposits
    4.4       50.0  
Accounts, notes and interest receivable, net
    831.6       951.8  
Inventories
    93.0       92.0  
Gas in underground storage
    27.4       2.2  
Fair value of derivative contracts
    35.2       24.0  
Other current assets
    17.7       37.6  
Total current assets
    1,187.7       1,286.7  
                 
Property, plant and equipment, net
    14,695.5       14,603.9  
Investments
    3,903.0       3,886.0  
Notes receivable
    117.9       115.0  
Goodwill
    1,229.4       1,233.6  
Other intangibles, net
    289.3       302.2  
Fair value of derivative contracts
    190.9       260.7  
Deferred charges and other assets
    179.6       173.0  
Total Assets
  $ 21,793.3     $ 21,861.1  
                 
LIABILITIES AND PARTNERS’ CAPITAL
               
Current liabilities
               
Current portion of debt
  $ 1,333.2     $ 1,262.4  
Cash book overdrafts
    35.9       32.5  
Accounts payable
    588.2       630.9  
Accrued interest
    91.6       239.6  
Accrued taxes
    78.1       44.7  
Deferred revenues
    103.7       96.6  
Fair value of derivative contracts
    380.5       281.5  
Accrued other current liabilities
    165.0       176.0  
Total current liabilities
    2,776.2       2,764.2  
                 
Long-term liabilities and deferred credits
               
Long-term debt
               
Outstanding
    10,415.6       10,277.4  
Value of interest rate swaps
    530.4       604.9  
Total Long-term debt
    10,946.0       10,882.3  
Deferred income taxes
    245.7       248.3  
Fair value of derivative contracts
    282.3       172.2  
Other long-term liabilities and deferred credits
    445.5       501.6  
Total long-term liabilities and deferred credits
    11,919.5       11,804.4  
                 
Total Liabilities
    14,695.7       14,568.6  
                 
Commitments and contingencies (Notes 4 and 10)
               
Partners’ Capital
               
Common units
    4,217.4       4,282.2  
Class B units
    59.6       63.1  
i-units
    2,850.4       2,807.5  
General partner
    247.6       244.3  
Accumulated other comprehensive loss
    (356.6 )     (186.4 )
Total Kinder Morgan Energy Partners, L.P. partners’ capital
    7,018.4       7,210.7  
Noncontrolling interests
    79.2       81.8  
Total Partners’ Capital
    7,097.6       7,292.5  
Total Liabilities and Partners’ Capital
  $ 21,793.3     $ 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)

   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Cash Flows From Operating Activities
           
Net Income
  $ 340.9     $ 227.4  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    221.8       227.3  
Amortization of excess cost of equity investments
    1.5       1.4  
Noncash compensation expense allocated from parent (Note 9)
    89.9       1.4  
Earnings from equity investments
    (64.9 )     (46.7 )
Distributions from equity investments
    64.8       49.8  
Changes in components of working capital:
               
Accounts receivable
    99.7       49.0  
Inventories
    -       (7.5 )
Other current assets
    20.0       23.8  
Accounts payable
    (39.1 )     (9.1 )
Accrued interest
    (148.0 )     (127.8 )
Accrued taxes
    33.5       6.1  
Accrued liabilities
    (20.9 )     (12.4 )
Rate reparations, refunds and other litigation reserve adjustments
    (63.0 )     158.0  
Other, net
    (18.7 )     (25.9 )
Net Cash Provided by Operating Activities
    517.5       514.8  
                 
Cash Flows From Investing Activities
               
Acquisitions of assets and investments
    (65.9 )     (226.3 )
Capital expenditures
    (265.0 )     (218.8 )
Sale or casualty of property, plant and equipment, and other net assets net of removal costs
    0.9       13.4  
Net proceeds from margin and restricted deposits
    43.2       15.9  
Contributions to equity investments
    (22.2 )     (135.6 )
Distributions from equity investments in excess of cumulative earnings
    79.1       57.3  
Net Cash Used in Investing Activities
    (229.9 )     (494.1 )
                 
Cash Flows From Financing Activities
               
Issuance of debt
    2,522.7       957.0  
Payment of debt
    (2,304.6 )     (524.0 )
Debt issue costs
    (7.1 )     (0.2 )
Increase in cash book overdrafts
    3.4       10.8  
Proceeds from issuance of common units
    81.2       -  
Contributions from noncontrolling interests
    1.8       1.7  
Distributions to partners and noncontrolling interests:
               
Common units
    (247.4 )     (217.7 )
Class B units
    (6.0 )     (5.6 )
General Partner
    (278.2 )     (245.5 )
Noncontrolling interests
    (6.6 )     (6.0 )
Net Cash Used in Financing Activities
    (240.8 )     (29.5 )
                 
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    2.5       (3.4 )
                 
Net increase (decrease) in Cash and Cash Equivalents
    49.3       (12.2 )
Cash and Cash Equivalents, beginning of period
    129.1       146.6  
Cash and Cash Equivalents, end of period
  $ 178.4     $ 134.4  
                 
Noncash Investing and Financing Activities
               
Assets acquired by the assumption or incurrence of liabilities
  $ -     $ 10.5  
Assets acquired by the issuance of common units
  $ -     $ 81.7  
Contribution of net assets to investments
  $ 7.9     $ -  
Supplemental Disclosures of Cash Flow Information
               
Cash paid during the period for interest (net of capitalized interest)
  $ 251.1     $ 213.5  
Cash paid during the period for income taxes
  $ 1.3     $ 2.7  

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 bulk materials like coal and petroleum coke.  We are also the leading provider of carbon dioxide for enhanced oil recovery projects in North America.  Our general partner is owned by Kinder Morgan, Inc., as discussed following.
 
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 March 31, 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 12.8% 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.”
 
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 correct 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 per Unit
 
We compute Limited Partners’ Net Income per Unit by dividing our limited partners’ interest in net income by the weighted average number of units outstanding during the period.  The overall computation, presentation, and disclosure requirements for our Limited Partners’ Net Income per Unit  are made in accordance with the “Earnings per Share” Topic of the Codification.
 
 
2.  Acquisitions, Joint Ventures, 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 balance sheet.  As of March 31, 2011, our $50.0 million investment is included within “Investments”  on our accompanying balance sheet.  The acquired investment complemented our existing rail transload operations.  We account for this 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.
 
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.
 
Joint Ventures
 
Deeprock North, LLC
 
On February 17, 2011, our subsidiary Kinder Morgan Cushing LLC and Mecuria Energy Trading, Inc. 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 in service by the end of the third 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 March 31, 2011, our net equity investment in Deeprock North, LLC totaled $16.0 million and is included within “Investments” on our accompanying consolidated balance sheet.  In April 2011, we contributed an additional $2.1 million to Deeprock North as partial funding for its ongoing tankage and truck rack expansion projects.
 
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 Taxes” in our accompanying consolidated statement of income for the three months ended March 31, 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.
 
Divestitures Subsequent to March 31, 2011                                                                       
 
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, both Oklahoma limited liability companies, for an aggregate consideration of $5.1 million, consisting of a $4.1 million note receivable and $1.0 million in cash.  Following the sale, we continue to own 49% membership interests in both River Consulting LLC, a Louisiana limited liability company engaged in the business of providing engineering, consulting and management services, and Devco USA L.L.C., an Oklahoma limited liability company engaged in the business of processing, handling and marketing sulfur, and selling related pouring equipment.  We now account for our retained investments under the equity method of accounting.  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 $7.5 million and consisted mostly of trade receivables and technology-based assets.  The sale of 51% of each of these two subsidiaries will not have a material impact on our results of operations or our cash flows.
 
 
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); (iii) Natural Gas Pipelines; (iv) CO2; (v) Terminals; and (vi) Kinder Morgan Canada.  There were no impairment charges resulting from our May 31, 2010 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 9.0%.  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 three months ended March 31, 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.
    -       -       -       -       -       -  
Disposals(b).
    -       -       -       (10.6 )     -       (10.6 )
Impairments
    -       -       -       -       -       -  
Currency translation adjustments
    -       -       -       -       6.4       6.4  
Balance as of March 31, 2011
  $ 263.2     $ 337.0     $ 46.1     $ 327.3     $ 255.8     $ 1,229.4  
__________

(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 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)
First quarter 2011 disposal related to the sale of our ownership interest in the boat fleeting business we acquired from Megafleet Towing Co., Inc. in April 2009 (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 three months of 2011.  As of March 31, 2011 and December 31, 2010, we reported $286.9 million and $283.0 million, respectively, in equity method goodwill within the caption “Investments” in our accompanying consolidated balance sheets.  The increase in our equity method goodwill since December 31, 2010 was due to measurement period adjustments related to our acquisition of a 50% ownership interest in KinderHawk Field Services LLC in May 2010.
 
Other Intangibles
 
Excluding goodwill, our other intangible assets include customer relationships, contracts and agreements, technology-based assets, and lease value.  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):
 
   
March 31,
2011
   
December 31,
2010
 
Customer relationships, contracts and agreements
           
Gross carrying amount
  $ 398.8     $ 399.8  
Accumulated amortization
    (121.6 )     (112.0 )
Net carrying amount
    277.2       287.8  
                 
Technology-based assets, lease value and other
               
Gross carrying amount
    15.7       17.9  
Accumulated amortization
    (3.6 )     (3.5 )
Net carrying amount
    12.1       14.4  
                 
Total Other intangibles, net
  $ 289.3     $ 302.2  
 
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 months ended March 31, 2011 and 2010, the amortization expense on our intangibles totaled $9.7 million and $11.3 million, respectively.  As of March 31, 2011, the weighted average amortization period for our intangible assets was approximately 13.6 years, and our estimated amortization expense for these assets for each of the next five fiscal years (2012 – 2016) is approximately $33.4 million, $29.5 million, $26.4 million, $23.6 million and $19.9 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 March 31, 2011 and December 31, 2010 was $11,748.8 million and $11,539.8 million, respectively.  The weighted average interest rate on all of our borrowings was approximately 4.44% during the first quarter of 2011, and approximately 4.32% during the first quarter of 2010.

Our outstanding short-term debt as of March 31, 2011 was $1,333.2 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 $449.8 million as of March 31, 2011); (iii) $343.0 million of commercial paper borrowings; (iv) $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); (v) a $9.4 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); and (vi) a $7.3 million portion of 5.23% long-term senior notes (our subsidiary Kinder Morgan Texas Pipeline, L.P. is the obligor on the notes).
 

 

Credit Facility
 
Our $2.0 billion three-year, senior unsecured revolving credit facility expires June 23, 2013 and can be amended to allow for borrowings of up to $2.3 billion.  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 $2.0 billion commercial paper program.  There were no borrowings under the credit facility as of March 31, 2011 or as of December 31, 2010.
 
As of March 31, 2011, the amount available for borrowing under our credit facility was reduced by a combined amount of $579.8 million, consisting of $343.0 million of commercial paper borrowings and $236.8 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 $16.1 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (v) a combined $16.6 million in other letters of credit supporting other obligations of us and our subsidiaries.
 
Commercial Paper Program
 
Our commercial paper program provides for the issuance of $2.0 billion of commercial paper.  Our $2.0 billion unsecured three-year bank credit facility supports our commercial paper program, and borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.  As of March 31, 2011, we had $343.0 million of commercial paper outstanding with an average interest rate of approximately 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.  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 underwriting discounts and commissions, of $1,092.7 million, and we used the proceeds to reduce the borrowings under our commercial paper program.
 
In addition, 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.
 
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 this date, the net present value of the note (representing the outstanding balance included as debt on our accompanying consolidated balance sheet) was $9.4 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 quarter of 2011, we paid a combined principal amount of $1.8 million, and as of March 31, 2011, Kinder Morgan Texas Pipeline L.P.’s outstanding balance under the senior notes was $21.8 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.
 
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.  Most of these agreements are with entities that are not consolidated in our financial statements; however, we have invested in and hold equity ownership interests in these entities.
 
As of March 31, 2011, our contingent debt obligations with respect to these investments, as well as our obligations with respect to related letters of credit, are summarized below (dollars in millions):
 
Entity
 
Our Ownership Interest
 
Investment Type
 
Total
Entity
Debt
     
Our Contingent
Share of
Entity Debt
 
(a)
Fayetteville Express Pipeline LLC(b)
    50 %
Limited Liability
  $ 962.5  
(c)
  $ 481.3    
  
                             
Cortez Pipeline Company(d)
    50 %
General Partner
  $ 140.1  
(e)
  $ 86.2  
(f)
                               
Nassau County,
Florida Ocean Highway and Port Authority(g)
    N/A  
N/A
    N/A       $ 18.3  
(h)
_________

(a)
Represents the portion of the entity’s debt that we may be responsible for if the entity cannot satisfy its obligations.
 
(b)
Fayetteville Express Pipeline LLC is a limited liability company and the owner of the Fayetteville Express natural gas pipeline system.  The remaining limited liability company member interest in Fayetteville Express Pipeline LLC is owned by Energy Transfer Partners, L.P.
 
(c)
Amount represents borrowings under a $1.1 billion, unsecured revolving bank credit facility that is due May 11, 2012.
 
(d)
Cortez Pipeline Company is a Texas general partnership that owns and operates a common carrier carbon dioxide pipeline system. The remaining general partner interests are owned by ExxonMobil Cortez Pipeline, Inc., an indirect wholly-owned subsidiary of Exxon Mobil Corporation, and Cortez Vickers Pipeline Company, an indirect subsidiary of M.E. Zuckerman Energy Investors Incorporated.
 
(e)
Amount consists of (i) $32.1 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) $8.0 million of outstanding borrowings under a $40.0 million committed revolving bank credit facility that is also due December 11, 2012.
 
(f)
We are severally liable for our percentage ownership share (50%) of the Cortez Pipeline Company debt ($70.1 million).  In addition, as of March 31, 2011, Shell Oil Company shares our several guaranty obligations jointly and severally for $32.1 million of Cortez’s debt balance related to the Series D notes; however, we are obligated to indemnify Shell for the liabilities it incurs in connection with such guaranty.  Accordingly, as of March 31, 2011, we have a letter of credit in the amount of $16.1 million issued by JP Morgan Chase, in order to secure our indemnification obligations to Shell for 50% of the Cortez debt balance of $32.1 million related to the Series D notes.
 
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.
 
(g)
Arose from our Vopak terminal acquisition in July 2001.  Nassau County, Florida Ocean Highway and Port Authority is a political subdivision of the state of Florida.
 
(h)
We have posted a letter of credit 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 March 31, 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.  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 March 31, 2011 and December 31, 2010, our partners’ capital included the following limited partner units:
 
   
March 31,
   
December 31,
 
   
2011
   
2010
 
Common units
    220,012,759       218,880,103  
Class B units
    5,313,400       5,313,400  
i-units
    93,506,543       91,907,987  
Total limited partner units
    318,832,702       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 incentive distribution rights.
 
As of March 31, 2011, our total common units consisted of 203,642,331 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 March 31, 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 March 31, 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 month periods ended March 31, 2011 and 2010, changes in the carrying amounts of our Partners’ Capital attributable to both us and our noncontrolling interests, including our comprehensive income (loss) are summarized as follows (in millions):
 
   
Three Months Ended March 31,
 
   
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
    -       -       -       81.7       -       81.7  
Units issued for cash
    81.2       -       81.2       -       -       -  
Distributions paid in cash
    (531.6 )     (6.6 )     (538.2 )     (468.8 )     (6.0 )     (474.8 )
Noncash compensation expense allocated from KMI(a)
    89.0       0.9       89.9       1.4       -       1.4  
Cash contributions
    -       1.8       1.8       -       1.7       1.7  
Other adjustments
    1.3       -       1.3       -       -       -  
                                                 
Comprehensive income:
                                               
Net Income
    337.8       3.1       340.9       225.3       2.1       227.4  
Other comprehensive income:
                                               
Change in fair value of derivatives utilized for hedging purposes
    (259.8 )     (2.6 )     (262.4 )     24.4       0.2       24.6  
Reclassification of change in fair value of derivatives to  net income
    52.5       0.5       53.0       47.0       0.5       47.5  
Foreign currency translation adjustments
    50.1       0.5       50.6       59.2       0.6       59.8  
Adjustments to pension and other postretirement benefit plan liabilities
    (13.0 )     (0.2 )     (13.2 )     (2.3 )     -       (2.3 )
Total other comprehensive income(loss)
    (170.2 )     (1.8 )     (172.0 )     128.3       1.3       129.6  
Comprehensive income
    167.6       1.3       168.9       353.6       3.4       357.0  
                                                 
Ending Balance
  $ 7,018.4     $ 79.2     $ 7,097.6     $ 6,612.6     $ 78.7     $ 6,691.3  
____________
 
(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 three 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 months ended March 31, 2011, we issued 1,130,206 of our common units pursuant to this equity distribution agreement, and after commissions of $0.6 million, we received net proceeds of $81.2 million 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.
 
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 February 14, 2011, we paid a cash distribution of $1.13 per unit to our common unitholders and to our Class B unitholder for the quarterly period ended December 31, 2010.  KMR, our sole i-unitholder, received a distribution of 1,598,556 i-units from us on February 14, 2011, based on the $1.13 per unit distributed to our common unitholders on that date.  The distributions were declared on January 19, 2011, payable to unitholders of record as of January 31, 2011.
 
Our February 14, 2011 incentive distribution payment to our general partner for the quarterly period ended December 31, 2010 totaled $274.6 million; however, this incentive distribution was affected by a waived incentive distribution equal to $7.0 million related to common units issued to finance a portion of our May 2010 acquisition of a 50% interest in KinderHawk Field Services LLC joint venture (our general partner has agreed not to take incentive distributions related to this acquisition through year-end 2011).  Our distribution of $1.05 per unit paid on February 12, 2010 for the fourth quarter of 2009 required an incentive distribution to our general partner of $242.3 million.  The increased incentive distribution to our general partner paid for the fourth quarter of 2010 over the incentive distribution paid for the fourth quarter of 2009 reflects the increase in the amount distributed per unit as well as the issuance of additional units.
 
Subsequent Events
 
In the first week of April 2011, we issued 114,690 of our common units for the settlement of sales made on or before March 31, 2011 pursuant to our equity distribution agreement.  After commissions of $0.1 million, we received net proceeds of $8.4 million for the issuance of these 114,690 common units, and we used the proceeds to reduce the borrowings under our commercial paper program.
 
On April 20, 2011, we declared a cash distribution of $1.14 per unit for the quarterly period ended March 31, 2011.  The distribution will be paid on May 13, 2011, to unitholders of record as of April 29, 2011.  Our common unitholders and our Class B unitholder will receive cash.  KMR will receive a distribution of 1,599,149 additional i-units based on the $1.14 distribution per common unit.  For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.017102) will be issued.  This fraction was determined by dividing:
 
▪ $1.14, the cash amount distributed per common unit
 
by
 
▪ $66.659, the average of KMR’s shares’ closing market prices from April 12-26, 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 first quarter of 2011 of $1.14 per unit will result in an incentive distribution to our general partner of $280.0 million (including the effect of a waived incentive distribution amount of $7.1 million related to our KinderHawk acquisition, as discussed above).  Comparatively, our distribution of $1.07 per unit paid on May 14, 2010 for the first quarter of 2010 resulted in an incentive distribution payment to our general partner in the amount of $249.4 million.
 

 

 
 
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 generally accepted accounting principles, the portion of the gain or loss on the derivative contract that is effective (as defined by 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 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 first quarter of 2011, we recognized a net gain of $3.7 million related to crude oil hedges and resulting from both hedge ineffectiveness and amounts excluded from effectiveness testing.  During the first quarter of 2010, we recognized a net gain of $6.3 million related to crude oil and natural gas hedges that resulted from hedge ineffectiveness and amounts excluded from effectiveness testing.
 
Additionally, during the three months ended March 31, 2011 and 2010, we reclassified losses of $53.0 million and $47.5 million, respectively, from “Accumulated other comprehensive loss” 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 loss” balance included in our Partners’ Capital was $356.6 million as of March 31, 2011, and $186.4 million as of December 31, 2010.  These totals included “Accumulated other comprehensive loss” amounts associated with energy commodity price risk management activities of $514.4 million as of March 31, 2011 and $307.1 million as of December 31, 2010.  Approximately $347.4 million of the total loss amount associated with energy commodity price risk management activities and included in our Partners’ Capital as of March 31, 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 March 31, 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 March 31, 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
(24.9) million barrels
Natural gas fixed price
     (28.8) billion cubic feet
Natural gas basis
     (28.8) billion cubic feet
Derivatives not designated as hedging contracts
 
Natural gas basis                           
                              1.7 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 March 31, 2011, we had a combined notional principal amount of $5,275 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 March 31, 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 January 15, 2038.
 
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 the first quarter of 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.
 
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 March 31, 2011 and December 31, 2010 (in millions):
 

 

 

 
Fair Value of Derivative Contracts
 
               
     
Asset derivatives
   
Liability derivatives
 
     
March 31,
   
December 31,
   
March 31,
   
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
  $ 19.9     $ 20.1     $ (372.4 )   $ (275.9 )
 
Non-current
    24.6       43.1       (189.9 )     (103.0 )
Subtotal
      44.5       63.2       (562.3 )     (378.9 )
                                   
Interest rate swap agreements
Current
    10.6       -       -       -  
 
Non-current
    166.3       217.6       (92.4 )     (69.2 )
Subtotal
      176.9       217.6       (92.4 )     (69.2 )
                                   
Total
      221.4       280.8       (654.7 )     (448.1 )
                                   
Derivatives not designated as hedging contracts
                                 
Energy commodity derivative contracts
Current
    4.7       3.9       (8.1 )     (5.6 )
Total
      4.7       3.9       (8.1 )     (5.6 )
                                   
Total derivatives
    $ 226.1     $ 284.7     $ (662.8 )   $ (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 March 31, 2011 and December 31, 2010, this unamortized premium totaled $445.9 million and $456.5 million, respectively, and as of March 31, 2011, the weighted average amortization period for this premium was approximately 17.0 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 months ended March 31, 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)
 
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 items(a)
 
     
Three Months Ended
       
Three Months Ended
 
     
March 31,
       
March 31,
 
     
2011
   
2010
       
2011
   
2010
 
Interest rate swap agreements
Interest, net – income/(expense)
  $ (63.9 )   $ 65.6  
Fixed rate debt
Interest, net – income/(expense)
  $ 63.9     $ (65.6 )
Total
    $ (63.9 )   $ 65.6  
Total
    $ 63.9     $ (65.6 )
____________
 
(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.  Amounts do not reflect the impact on interest expense from the interest rate swap agreements under which we pay variable rate interest and receive fixed rate interest.
 








Derivatives in cash flow hedging relationships
Amount of gain/(loss) recognized in OCI on derivative (effective portion)
 
Location of gain/(loss) reclassified 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
   
Three Months
   
Three Months
 
 
Ended March 31,
   
Ended March 31,
   
Ended March 31,
 
 
2011
 
2010
   
2011
 
2010
   
2011
 
2010
 
Energy commodity derivative contracts
  $ (262.4 )   $ 24.6  
Revenues-natural gas sales
  $ 0.9     $ -  
Revenues-product sales and other
  $ 3.7     $ 5.4  
                 
Revenues-product sales and other
    (65.2 )     (50.0 )                  
                 
Gas purchases and other costs of sales
    11.3       2.5  
Gas purchases and other costs of sales
    -       0.9  
Total
  $ (262.4 )   $ 24.6  
Total
  $ (53.0 )   $ (47.5 )
Total
  $ 3.7     $ 6.3  
____________
 
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 March 31,
 
     
2011
   
2010
 
Energy commodity derivative contracts
Gas purchases and other costs of sales
  $ 0.1     $ 0.7  
Total
    $ 0.1     $ 0.7  
____________

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 March 31, 2011 was (in millions):
 
   
Asset position
 
Interest rate swap agreements
  $ 176.9  
Energy commodity derivative contracts
    49.2  
Gross exposure
    226.1  
Netting agreement impact
    (49.4 )
Net exposure
  $ 176.7  


 
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 March 31, 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 March 31, 2011, we had cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners totaling $4.4 million, and we reported this amount as “Restricted deposits” in our accompanying consolidated balance sheet.  As of December 31, 2010, our counterparties associated with our energy commodity contract positions and over-the–counter swap agreements had margin deposits with us totaling $2.4 million, and we reported this amount within “Accrued other liabilities” in our accompanying consolidated balance sheet.
 
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 March 31, 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
  $ -     $ 4.4  
                 
Two notches to below BBB-/Baa3 (below investment grade)
  $ 87.0     $ 91.4  
_________

(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 $87.0 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 March 31, 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 March 31, 2011
                       
Energy commodity derivative contracts(a)
  $ 49.2     $ 12.8     $ 6.9     $ 29.5  
Interest rate swap agreements
  $ 176.9     $ -     $ 176.9     $ -  
                                 
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 March 31, 2011
                       
Energy commodity derivative contracts(a)
  $ (570.4 )   $ (8.7 )   $ (529.0 )   $ (32.7 )
Interest rate swap agreements
  $ (92.4 )   $ -     $ (92.4 )   $ -  
                                 
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 months ended March 31, 2011 and 2010 (in millions):
 
Significant unobservable inputs (Level 3)
 
   
Three Months Ended
 
   
March 31,
 
   
2011
   
2010
 
Derivatives-net asset (liability)
           
Beginning of period
  $ 18.8     $ 13.0  
Transfers into Level 3
    -       -  
Transfers out of Level 3
    -       -  
Total gains or (losses)
    -       -  
     Included in earnings
    0.1       -  
     Included in other comprehensive income
    (22.8 )     8.6  
Purchases
    4.6       -  
Issuances
    -       -  
Sales
    -       -  
Settlements
    (3.9 )     1.0  
End of period
  $ (3.2 )   $ 22.6  
                 
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or (losses) relating to assets held at the reporting date
  $ -     $ (0.1 )

Fair Value of Financial Instruments
 
Fair value as used in the disclosure of financial instruments represents the amount at which an instrument could be exchanged in a current transaction between willing parties.  As of each reporting date, the estimated fair value of our outstanding publicly-traded debt is based upon quoted market prices, if available, and for all other debt, fair value is based upon prevailing interest rates currently available to us.  In addition, we adjust (discount) the fair value measurement of our long-term debt for the effect of credit risk.
 
The estimated fair value of our outstanding debt balance as of March 31, 2011 and December 31, 2010 (both short-term and long-term, but excluding the value of interest rate swaps) is disclosed below (in millions):
 
   
March 31, 2011
   
December 31, 2010
 
   
Carrying
Value
   
Estimated
fair value
   
Carrying
Value
   
Estimated
fair value
 
Total debt
  $ 11,748.8     $ 12,589.1     $ 11,539.8     $ 12,443.4  

 
8.  Reportable Segments
 
We divide our operations into five reportable business segments.  These segments and their principal source of revenues are as follows:
 
 
Products Pipelines— the transportation and terminaling of refined petroleum products, including gasoline, diesel fuel, jet fuel and natural gas liquids;
 
 
Natural Gas Pipelines—the sale, transport, processing, treating, storage and gathering of natural gas;
 
 
CO2—the production and sale of crude oil from fields in the Permian Basin of West Texas and the transportation and marketing of carbon dioxide used as a flooding medium for recovering crude oil from mature oil fields;
 
 
Terminals—the transloading and storing of refined petroleum products and dry and liquid bulk products, including coal, petroleum coke, cement, alumina, salt and other bulk chemicals; and
 

 
 
Kinder Morgan Canada—the transportation of crude oil and refined products from Alberta, Canada to marketing terminals and refineries in British Columbia, the state of Washington and the Rocky Mountains and Central regions of the United States.
 
We evaluate performance principally based on each segments’ earnings before depreciation, depletion and amortization expenses (including amortization of excess cost of equity investments), which excludes general and administrative expenses, third-party debt costs and interest expense, unallocable interest income, and unallocable income tax expense.  Our reportable segments are strategic business units that offer different products and services, and they are structured based on how our chief operating decision maker organizes their operations for optimal performance and resource allocation.  Each segment is managed separately because each segment involves different products and marketing strategies.
 
Financial information by segment follows (in millions):
 
   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Revenues
           
Products Pipelines
           
Revenues from external customers
  $ 225.6     $ 207.5  
Natural Gas Pipelines
               
Revenues from external customers
    1,019.4       1,236.7  
CO2
               
Revenues from external customers
    340.8       321.8  
Terminals
               
Revenues from external customers
    331.4       303.8  
Intersegment revenues
    0.3       0.3  
Kinder Morgan Canada
               
Revenues from external customers
    75.6       59.8  
Total segment revenues
    1,993.1       2,129.9  
Less: Total intersegment revenues
    (0.3 )     (0.3 )
Total consolidated revenues
  $ 1,992.8     $ 2,129.6  
 
   
Three Months Ended
March 31,
 
   
2011
   
2010
 
Segment earnings before depreciation, depletion, amortization
and amortization of excess cost of equity investments(a)
           
Products Pipelines(b)
  $ 180.5     $ 6.4  
Natural Gas Pipelines
    222.6       220.6  
CO2
    262.0       253.2  
Terminals
    174.4       150.5  
Kinder Morgan Canada
    47.9       45.0  
Total segment earnings before DD&A
    887.4       675.7  
Total segment depreciation, depletion and amortization
    (221.8 )     (227.3 )
Total segment amortization of excess cost of investments
    (1.5 )     (1.4 )
General and administrative expenses(c)
    (189.2 )     (101.1 )
Unallocable interest expense, net of interest income
    (131.7 )     (116.3 )
Unallocable income tax expense
    (2.3 )     (2.2 )
Total consolidated net income
  $ 340.9     $ 227.4  








   
March 31,
2011
   
December 31,
2010
 
Assets
           
Products Pipelines
  $ 4,375.1     $ 4,369.1  
Natural Gas Pipelines
    8,681.5       8,809.7  
CO2
    2,127.0       2,141.2  
Terminals
    4,243.6       4,138.6  
Kinder Morgan Canada
    1,901.4       1,870.0  
Total segment assets
    21,328.6       21,328.6  
Corporate assets(d)
    464.7       532.5  
Total consolidated assets
  $ 21,793.3     $ 21,861.1  
____________
 
(a)
Includes revenues, earnings from equity investments, allocable interest income, and other, net, less operating expenses, allocable income taxes, and other expense (income).
 
(b)
First quarter 2010 includes a $158.0 million increase in expense associated with rate case liability adjustments.
 
(c)
First quarter 2011 includes an $87.1 million increase in expense associated with a one-time special cash bonus payment that will be paid to non-senior management employees in May 2011; however, we do not have any obligation, nor do we expect to pay any amounts related to this expense.
 
(d)
Includes cash and cash equivalents; margin and restricted deposits; unallocable interest receivable, prepaid assets and deferred charges; and risk management assets related to the fair value of interest rate swaps.
 
 
9.  Related Party Transactions
 
Notes Receivable
 
Plantation Pipe Line Company
 
We have a current note receivable bearing interest at the rate of 4.72% per annum from Plantation Pipe Line Company, our 51.17%-owned equity investee.  The note provides for semiannual payments of principal and interest on June 30 and December 31 each year, with a final principal payment due July 20, 2011.  As of both March 31, 2011 and December 31, 2010, the outstanding note receivable balance was $82.1 million, and we included this amount within “Accounts, notes and interest receivable, net,” on our accompanying consolidated balance sheets.
 
Express US Holdings LP
 
In conjunction with the acquisition of our 33 1/3% equity ownership interest in the Express pipeline system from KMI on August 28, 2008, we acquired a long-term investment in a C$113.6 million debt security issued by Express US Holdings LP (the obligor), the partnership that maintains ownership of the U.S. portion of the Express pipeline system.  The debenture is denominated in Canadian dollars, due in full on January 9, 2023, bears interest at the rate of 12.0% per annum, and provides for quarterly payments of interest in Canadian dollars on March 31, June 30, September 30 and December 31 each year.  As of March 31, 2011 and December 31, 2010, the outstanding note receivable balance, representing the translated amount included in our consolidated financial statements in U.S. dollars, was $117.2 million and $114.2 million, respectively, and we included these amounts within “Notes receivable” on our accompanying consolidated balance sheets.
 
Other Receivables and Payables
 
As of March 31, 2011 and December 31, 2010, our related party receivables (other than notes receivable discussed above in “—Notes Receivable”) totaled $9.9 million and $15.4 million, respectively.  The March 31, 2011 amount included $7.8 million within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet, primarily consisting of amounts due from (i) Plantation Pipe Line Company; (ii) the Express pipeline system; and (iii) Natural Gas Pipeline Company of America LLC, a 20%-owned equity investee of KMI and referred to in this report as NGPL.  The December 31, 2010 receivables amount consisted of (i) $8.2 million included within “Accounts, notes and interest receivable, net” on our accompanying consolidated balance sheet; and (ii) $7.2 million of natural gas imbalance receivables included within “Other current assets.”  The $8.2 million amount primarily related to accounts and interest receivables due from (i) the Express pipeline system; (ii) NGPL; and (iii) Plantation Pipe Line Company.  Our related party natural gas imbalance receivables consisted of amounts due from NGPL.
 
As of March 31, 2011 and December 31, 2010, our related party payables totaled $8.4 million and $8.8 million, respectively.  The March 31, 2011 related party payable amount included a $6.7 million payable to KMI included within “Accounts payable” on our accompanying balance sheet.  The December 31, 2010 amount consisted of (i) $5.1 million included within “Accounts payable” and primarily related to amounts due to KMI; and (ii) $3.7 million of natural gas imbalance payables included within “Accrued other current liabilities” and consisting of amounts due to the Rockies Express pipeline system.
 
Asset Acquisitions
 
In conjunction with our acquisition of (i) certain Natural Gas Pipelines assets and partnership interests from KMI in December 1999 and December 2000; and (ii) all of the ownership interest in TransColorado Gas Transmission Company LLC from two wholly-owned subsidiaries of KMI on November 1, 2004, KMI agreed to indemnify us and our general partner with respect to approximately $733.5 million of our debt.  KMI would be obligated to perform under this indemnity only if we are unable, and/or our assets were insufficient, to satisfy our obligations.
 
Asset Divestitures
 
Mr. C. Berdon Lawrence, a non-management director on the boards of our general partner and KMR, is also Chairman Emeritus of the Board of Kirby Corporation.  On February 9, 2011, we sold a marine vessel to Kirby Corporation’s subsidiary Kirby Inland Marine, L.P., and additionally, we and Kirby Inland Marine L.P. formed a joint venture named Greens Bayou Fleeting, LLC.  For more information about these transactions, see Note 2.
 
Noncash Compensation Expense
 
In the first quarters of 2011 and 2010, KMI allocated to us certain noncash compensation expenses totaling $89.9 million and $1.4 million, respectively.  The amounts included expenses of $2.8 million and $1.4 million, respectively, associated with KMI’s May 2007 going–private transaction, and for 2011 only, an expense of $87.1 million associated with a one-time special cash bonus payment that will be paid to non-senior management employees in May 2011.  However, we do not have any obligation, nor do we expect to pay any amounts related to these compensation expenses, and since we will not be responsible for paying these expenses, we recognized the amounts allocated to us as both an expense on our income statement and a contribution to “Total Partners’ Capital” on our balance sheet.
 
Derivative Counterparties
 
As a result of KMI’s going-private transaction in May 2007, a number of individuals and entities became significant investors in KMI, and by virtue of the size of its ownership interest in KMI, one of those investors—Goldman Sachs Capital Partners and certain of its affiliates—remains a “related party” (as that term is defined in authoritative accounting literature) to us as of March 31, 2011.  Goldman Sachs has also acted in the past, and may act in the future, as an underwriter for equity and/or debt issuances for us, and Goldman Sachs effectively owned 49% of the terminal assets we acquired from US Development Group LLC in January 2010.
 
In addition, we conduct energy commodity risk management activities in the ordinary course of implementing our risk management strategies in which the counterparty to certain of our derivative transactions is an affiliate of Goldman Sachs, and in conjunction with these activities, we are a party (through one of our subsidiaries engaged in the production of crude oil) to a hedging facility with J. Aron & Company/Goldman Sachs.  The hedging facility requires us to provide certain periodic information, but does not require the posting of margin.  As a result of changes in the market value of our derivative positions, we have created both amounts receivable from and payable to Goldman Sachs affiliates.
 
The following table summarizes the fair values of our energy commodity derivative contracts that are (i) associated with commodity price risk management activities with J. Aron & Company/Goldman Sachs; and (ii) included within “Fair value of derivative contracts” on our accompanying consolidated balance sheets as of March 31, 2011 and December 31, 2010 (in millions):
 

 
   
March 31,
2011
   
December 31,
2010
 
Derivatives – asset/(liability)
           
Current assets
  $ 3.7     $ -  
Noncurrent assets
  $ 3.7     $ 12.7  
Current liabilities
  $ (281.4 )   $ (221.4 )
Noncurrent liabilities
  $ (86.9 )   $ (57.5 )

For more information on our risk management activities see Note 6.
 
Other
 
Generally, KMR makes all decisions relating to the management and control of our business, and in general, KMR has a fiduciary duty to manage us in a manner beneficial to our unitholders.  Our general partner owns all of KMR’s voting securities and elects all of KMR’s directors.  KMI indirectly owns all the common stock of our general partner, and the officers of KMI have fiduciary duties to manage KMI, including selection and management of its investments in its subsidiaries and affiliates, in a manner beneficial to the owners of KMI.  Accordingly, certain conflicts of interest could arise as a result of the relationships among KMR, our general partner, KMI and us.
 
The partnership agreements for us and our operating partnerships contain provisions that allow KMR to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duty to our unitholders, as well as provisions that may restrict the remedies available to our unitholders for actions taken that might, without such limitations, constitute breaches of fiduciary duty.  The partnership agreements also provide that in the absence of bad faith by KMR, the resolution of a conflict by KMR will not be a breach of any duties.  The duty of the officers of KMI may, therefore, come into conflict with the duties of KMR and its directors and officers to our unitholders.  The audit committee of KMR’s board of directors will, at the request of KMR, review (and is one of the means for resolving) conflicts of interest that may arise between KMI or its subsidiaries, on the one hand, and us, on the other hand.
 
For a more complete discussion of our related party transactions, including (i) the accounting for our general and administrative expenses; (ii) KMI’s operation and maintenance of the assets comprising our Natural Gas Pipelines business segment; and (iii) our partnership interests and distributions, see Note 11 to our consolidated financial statements included in our 2010 Form 10-K/A.
 
 
10.  Litigation, Environmental and Other Contingencies
 
Below is a brief description of our ongoing material legal proceedings, including any material developments that occurred in such proceedings during the three months ended March 31, 2011.  Additional information with respect to these proceedings can be found in Note 16 to our consolidated financial statements that were included in our 2010 Form 10-K/A.  This note also contains a description of any material legal proceedings that were initiated against us during the three months ended March 31, 2011, and a description of any material events occurring subsequent to March 31, 2011 but before the filing of this report.
 
In this note, we refer to our subsidiary SFPP, L.P. as SFPP; our subsidiary Calnev Pipe Line LLC as Calnev; Chevron Products Company as Chevron; BP West Coast Products, LLC as BP; ConocoPhillips Company as ConocoPhillips; Tesoro Refining and Marketing Company as Tesoro; Western Refining Company, L.P. as Western Refining; ExxonMobil Oil Corporation as ExxonMobil; Valero Energy Corporation as Valero; Valero Marketing and Supply Company as Valero Marketing; Continental Airlines, Inc., Northwest Airlines, Inc., Southwest Airlines Co. and US Airways, Inc., collectively, as the Airlines; our subsidiary Kinder Morgan CO2 Company, L.P. (the successor to Shell CO2 Company, Ltd.) as Kinder Morgan CO2; the United States Court of Appeals for the District of Columbia Circuit as the D.C. Circuit; the Federal Energy Regulatory Commission as the FERC; the California Public Utilities Commission as the CPUC; the Union Pacific Railroad Company (the successor to Southern Pacific Transportation Company) as UPRR;  the Texas Commission of Environmental Quality as the TCEQ; The Premcor Refining Group, Inc. as Premcor; Port Arthur Coker Company as PACC; our subsidiary Kinder Morgan Bulk Terminals, Inc. as KMBT; our subsidiary Kinder Morgan Liquids Terminals LLC as KMLT; our subsidiary Kinder Morgan Interstate Gas Transmission LLC as KMIGT; Rockies Express Pipeline LLC as Rockies Express; and Plantation Pipe Line Company as Plantation.  “OR” dockets designate complaint proceedings, and “IS” dockets designate protest proceedings.
 
Federal Energy Regulatory Commission Proceedings
 
The tariffs and rates charged by SFPP and Calnev are subject to a number of ongoing proceedings at the FERC, including the shippers' complaints and protests regarding interstate rates on the pipeline systems listed below.  In general, these complaints and protests allege the rates and tariffs charged by SFPP and Calnev are not just and reasonable.  If the shippers are successful in proving their claims, they are entitled to seek reparations (which may reach up to two years prior to the filing of their complaints) or refunds of any excess rates paid, and SFPP may be required to reduce its rates going forward.  These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts.
 
The issues involved in these proceedings include, among others: (i) whether certain of our Pacific operations’ rates are “grandfathered” under the Energy Policy Act of 1992, and therefore deemed to be just and reasonable; (ii) whether “substantially changed circumstances” have occurred with respect to any grandfathered rates such that those rates could be challenged; (iii) whether indexed rate increases are justified; and (iv) the appropriate level of return and income tax allowance we may include in our rates.
 
 
SFPP
 
Pursuant to FERC approved settlements, SFPP settled with eleven of twelve shipper litigants in May 2010 and with Chevron on March 15, 2011 a wide range of rate challenges dating back to 1992 (Historical Cases Settlements).  Settlement payments were made to Chevron in March 2011 and the following FERC dockets that were pending only as to Chevron were resolved: FERC Docket Nos. OR92-8, et al.; OR96-2, et al.; OR02-4; OR03-5; OR07-4; OR09-8 (consolidated); IS98-1; IS05-230; IS07-116; IS08-137;  IS08-302; and IS09-375.  The following appellate review proceedings that were pending before the D.C. Circuit only as to Chevron were also resolved: D.C. Circuit Case Nos. 03-1183; 06-1017 and 06-1128.  In connection with the Historical Cases Settlements, the FERC issued an order directing SFPP to pay refunds to non-litigant shippers and to collect overpaid refunds from non-litigant shippers.  The Historical Cases Settlements resolved all but two of the cases outstanding between SFPP and the twelve litigant shippers, and SFPP does not expect any material adverse impacts from the remaining two unsettled cases.
 
The Historical Cases Settlements and other legal reserves related to SFPP rate litigation resulted in a $172.0 million charge to earnings in 2010.  In June 2010, we made settlement payments of $206.3 million to eleven of the litigant shippers.  Due to this settlement payment and the reserve we took at that time for potential future settlements with Chevron and our CPUC cases described below, a portion of our partnership distributions for the second quarter of 2010 (which we paid in August 2010) was a distribution of cash from interim capital transactions (rather than a distribution of cash from operations).  As a result, our general partner’s cash distributions for the second quarter of 2010 were reduced by $170.0 million.  As provided in our partnership agreement, our general partner receives no incentive distribution on distributions of cash from interim capital transactions; accordingly, our second quarter 2010 interim capital transaction distribution increased our cumulative excess cash coverage (cumulative excess cash coverage is cash from operations generated since our inception in excess of cash distributions paid).  This interim capital transaction also allowed us to resolve the Chevron cases and should allow us to resolve the CPUC rate cases (discussed below) without impacting future distributions.  For more information on our partnership distributions, see Note 10 “Partners’ Capital—Income Allocation and Declared Distributions” to our consolidated financial statements included in our 2010 Form 10-K/A.
 
 
The following FERC dockets, which pertain to all protesting shippers, are currently pending:
 
 
FERC Docket No. IS08-390 (West Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, the Airlines—Status: FERC order issued on February 17, 2011.  While the order made certain findings that were adverse to SFPP, it ruled in favor of SFPP on many significant issues.  Subsequently, SFPP made a compliance filing which estimates approximately $16.0 million in refunds.  However, SFPP also filed a rehearing request on certain adverse rulings in the FERC order.  It is not possible to predict the outcome of the FERC review of the rehearing request or appellate review of this order; and
 
 
FERC Docket No. IS09-437 (East Line Rates)—Protestants: BP, ExxonMobil, ConocoPhillips, Valero Marketing, Chevron, Western Refining, and Southwest Airlines—Status: Initial decision issued on February 10, 2011.  A FERC administrative law judge generally made findings adverse to SFPP, found that East Line rates should have been lower, and recommended that SFPP pay refunds for alleged over-collections.  SFPP has filed a brief with the FERC taking exception to these and other portions of the initial decision.  The FERC will review the initial decision, and while the initial decision is inconsistent with a number of the issues ruled on in FERC’s February 17, 2011 order in Docket No. IS08-390, it is not possible to predict the outcome of FERC or appellate review.
 
 
 
 
 
Calnev
 
On March 17, 2011, the FERC issued an order consolidating the following proceedings and setting them for hearing.  The FERC further held the hearing proceedings in abeyance to allow for settlement judge proceedings:

 
FERC Docket Nos. OR07-7, OR07-18, OR07-19 & OR07-22 (not consolidated) (Calnev Rates)—Complainants: Tesoro, Airlines, BP, Chevron, ConocoPhillips and Valero Marketing—Status:  Before a FERC settlement judge; and
 
 
FERC Docket Nos. OR09-15/OR09-20 (not consolidated) (Calnev Rates)—Complainants: Tesoro/BP—Status:  Before a FERC settlement judge.

The following docket is currently pending:

 
FERC Docket No. IS09-377 (2009 Index Rate Increases)—Protestants: BP, Chevron, and Tesoro—Status:  Requests for rehearing of FERC dismissal pending before FERC.
 
 
Trailblazer Pipeline Company LLC
 
On July 7, 2010, our subsidiary Trailblazer Pipeline Company LLC refunded a total of approximately $0.7 million to natural gas shippers covering the period January 1, 2010 through May 31, 2010 as part of a settlement reached with shippers to eliminate the December 1, 2009 rate filing obligation contained in its Docket No. RP03-162 rate case settlement.  As part of the agreement with shippers, Trailblazer commenced billing reduced tariff rates as of June 1, 2010 with an additional reduction in tariff rates that took effect January 1, 2011.
 
 
Kinder Morgan Interstate Gas Transmission LLC Section 5 Proceeding
 
On November 18, 2010, our subsidiary KMIGT was notified by the FERC of a proceeding against it pursuant to Section 5 of the Natural Gas Act.  The proceeding set for hearing a determination of whether KMIGT’s current rates, which were approved by the FERC in KMIGT’s last transportation rate case settlement, remain just and reasonable.  The FERC made no findings in its order as to what would constitute just and reasonable rates or a reasonable return for KMIGT.  A proceeding under Section 5 of the Natural Gas Act is prospective in nature and any potential change in rates charged customers by KMIGT can only occur after the FERC has issued a final order.  Prior to that, an administrative law judge presides over an evidentiary hearing and makes an initial decision (which the FERC has directed to be issued within 47 weeks).  On March 23, 2011 the Chief Judge suspended the procedural schedule in this proceeding because all parties have reached a settlement in principle that will resolve all issues set for hearing.  The settlement, which is supported or not opposed by all parties of record, is currently estimated to be filed with the Chief Judge in the first week of May 2011.  If accepted by the administrative law judge, the settlement is subject to approval by the FERC before any rate change is effective.
 
California Public Utilities Commission Proceedings
 
SFPP has previously reported ratemaking and complaint proceedings pending with the CPUC.  The ratemaking and complaint cases generally involve challenges to rates charged by SFPP for intrastate transportation of refined petroleum products through its pipeline system in the state of California and request prospective rate adjustments and refunds with respect to tariffed and previously untariffed charges for certain pipeline transportation and related services.  These matters have been consolidated and assigned to two administrative law judges. 
 
On April 6, 2010, a CPUC administrative law judge issued a proposed decision in several intrastate rate cases involving SFPP and a number of its shippers.  The proposed decision includes determinations on issues, such as SFPP’s entitlement to an income tax allowance and allocation of environmental expenses, that we believe are contrary both to CPUC policy and precedent and to established federal regulatory policies for pipelines.  Moreover, the proposed decision orders refunds relating to these issues where the underlying rates were previously deemed reasonable by the CPUC, which we believe to be contrary to California law.  Based on our review of these CPUC proceedings, we estimate that our maximum exposure is approximately $220 million in reparation and refund payments and if the determinations made in the proposed decision were applied prospectively in two pending cases this could result in approximately $30 million in annual rate reductions.
 
The proposed decision is advisory in nature and can be rejected, accepted or modified by the CPUC.  SFPP filed comments on May 3, 2010 outlining what it believes to be the errors in law and fact within the proposed decision, and on May 5, 2010, SFPP made oral arguments before the full CPUC.  On November 12, 2010, an alternate proposed decision was issued.  The matter remains pending before the CPUC, which may act at any time at its scheduled bimonthly meetings.  Further procedural steps, including motions for rehearing and writ of review to California’s Court of Appeals, will be taken if warranted.  We do not expect the final resolution of this matter to have an adverse effect on our financial position or on our results of operations for 2011.
 
Carbon Dioxide Litigation
 
CO2 Claims Arbitration
 
Kinder Morgan CO2 and Cortez Pipeline Company were among the named defendants in CO2 Committee, Inc. v. Shell Oil Co., et al., an arbitration initiated on November 28, 2005.  The arbitration arose from a dispute over a class action settlement agreement which became final on July 7, 2003 and disposed of five lawsuits formerly pending in the U.S. District Court, District of Colorado.  The plaintiffs in such lawsuits primarily included overriding royalty interest owners, royalty interest owners, and small share working interest owners who alleged underpayment of royalties and other payments on carbon dioxide produced from the McElmo Dome unit. 
 
The settlement imposed certain future obligations on the defendants in the underlying litigation.  The plaintiffs in the arbitration alleged that, in calculating royalty and other payments, defendants used a transportation expense in excess of what is allowed by the settlement agreement, thereby causing alleged underpayments of approximately $12 million.  The plaintiffs also alleged that Cortez Pipeline Company should have used certain funds to further reduce its debt, which, in turn, would have allegedly increased the value of royalty and other payments by approximately $0.5 million.  On August 7, 2006, the arbitration panel issued its opinion finding that defendants did not breach the settlement agreement.  On June 21, 2007, the New Mexico federal district court entered final judgment confirming the August 7, 2006 arbitration decision.
 
On October 2, 2007, the plaintiffs initiated a second arbitration (CO2 Committee, Inc. v. Shell CO2 Company, Ltd., aka Kinder Morgan CO2 Company, L.P., et al.) against Cortez Pipeline Company, Kinder Morgan CO2 and an ExxonMobil entity.  The second arbitration asserts claims similar to those asserted in the first arbitration.  A second arbitration panel has convened and a final hearing on the parties’ claims and defenses is expected to occur in 2011.

Colorado Severance Tax Assessment
 
On September 16, 2009, the Colorado Department of Revenue issued three Notices of Deficiency to Kinder Morgan CO2.  The Notices of Deficiency assessed additional state severance tax against Kinder Morgan CO2 with respect to carbon dioxide produced from the McElmo Dome unit for tax years 2005, 2006, and 2007.  The total amount of tax assessed was $5.7 million, plus interest of $1.0 million, plus penalties of $1.7 million.  Kinder Morgan CO2 protested the Notices of Deficiency and paid the tax and interest under protest.  Kinder Morgan CO2 is now awaiting the Colorado Department of Revenue’s response to the protest.
 
Montezuma County, Colorado Property Tax Assessment
 
In November of 2009, the County Treasurer of Montezuma County, Colorado, issued to Kinder Morgan CO2, as operator of the McElmo Dome unit, retroactive tax bills for tax year 2008, in the amount of $2 million.  Of this amount, 37.2% is attributable to Kinder Morgan CO2’s interest.  The retroactive tax bills were based on the assertion that a portion of the actual value of the carbon dioxide produced from the McElmo Dome unit was omitted from the 2008 tax roll due to an alleged over statement of transportation and other expenses used to calculate the net taxable value. Kinder Morgan CO2 paid the retroactive tax bills under protest and will file petitions for refunds of the taxes paid under protest and will vigorously contest Montezuma County’s position.
 
Other
 
In addition to the matters listed above, audits and administrative inquiries concerning Kinder Morgan CO2’s payments on carbon dioxide produced from the McElmo Dome and Bravo Dome units are currently ongoing.  These audits and inquiries involve federal agencies, the states of Colorado and New Mexico, and county taxing authorities in the state of Colorado.
 

 
Commercial Litigation Matters
 
Union Pacific Railroad Company Easements
 
SFPP and UPRR are engaged in a proceeding to determine the extent, if any, to which the rent payable by SFPP for the use of pipeline easements on rights-of-way held by UPRR should be adjusted pursuant to existing contractual arrangements for the ten year period beginning January 1, 2004 (Union Pacific Railroad Company vs. Santa Fe Pacific Pipelines, Inc., SFPP, L.P., Kinder Morgan Operating L.P. “D”, Kinder Morgan G.P., Inc., et al., Superior Court of the State of California for the County of Los Angeles, filed July 28, 2004).  In February 2007, a trial began to determine the amount payable for easements on UPRR rights-of-way.  The trial is ongoing and is expected to conclude by the end of the second quarter of 2011, with a decision from the judge expected by the end of 2011.
 
SFPP and UPRR are also engaged in multiple disputes over the circumstances under which SFPP must pay for a relocation of its pipeline within the UPRR right-of-way and the safety standards that govern relocations.  In July 2006, a trial before a judge regarding the circumstances under which SFPP must pay for relocations concluded, and the judge determined that SFPP must pay for any relocations resulting from any legitimate business purpose of the UPRR.  SFPP appealed this decision, and in December 2008, the appellate court affirmed the decision.  In addition, UPRR contends that SFPP must comply with the more expensive American Railway Engineering and Maintenance-of-Way standards in determining when relocations are necessary and in completing relocations.  Each party is seeking declaratory relief with respect to its positions regarding the application of these standards with respect to relocations.
 
Since SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations, it is difficult to quantify the effects of the outcome of these cases on SFPP.  Even if SFPP is successful in advancing its positions, significant relocations for which SFPP must nonetheless bear the expense (i.e., for railroad purposes, with the standards in the federal Pipeline Safety Act applying) would have an adverse effect on our financial position and results of operations.  These effects would be even greater in the event SFPP is unsuccessful in one or more of these litigations.
 
Severstal Sparrows Point Crane Collapse
 
On June 4, 2008, a bridge crane owned by Severstal Sparrows Point, LLC and located in Sparrows Point, Maryland collapsed while being operated by KMBT.  According to our investigation, the collapse was caused by unexpected, sudden and extreme winds.  On June 24, 2009, Severstal filed suit against KMBT in the United States District Court for the District of Maryland, cause no. WMN 09CV1668.  Severstal alleges that KMBT was contractually obligated to replace the collapsed crane and that its employees were negligent in failing to properly secure the crane prior to the collapse.  Severstal seeks unspecified damages for value of the crane and lost profits.  KMBT denies each of Severstal’s allegations.
 
JR Nicholls Tug Incident
 
On February 10, 2010, the JR Nicholls, a tugboat operated by one of our subsidiaries, overturned and sank in the Houston Ship Channel.  Five employees were on board and four were rescued, treated and released from a local hospital.  The fifth employee died in the incident.  The U.S. Coast Guard shut down a section of the ship channel for approximately 60 hours.  Approximately 2,200 gallons of diesel fuel was released from the tugboat.  Emergency response crews deployed booms and contained the product, which was substantially cleaned up.  Salvage operations were commenced and the tugboat has been recovered.  A full investigation of the incident is underway.  Our subsidiary J.R. Nicholls LLC filed a limitations action entitled In the Matter of the Complaint of J.R. Nicholls LLC as Owner of the M/V J.R. NICHOLLS For Exoneration From or Limitation of Liability, CA No. 4:10-CV-00449, U.S. District Court, S.D. Tex.  To date, three surviving crew members have filed claims in that action for personal injuries and emotional distress.  On September 15, 2010, our subsidiary KM Ship Channel Services LLC, agreed to pay a civil penalty of $7,500 to the United States Coast Guard for the unintentional discharge of diesel fuel which occurred when the vessel sank.
 
The Premcor Refining Group, Inc. v. Kinder Morgan Energy Partners, L.P. and Kinder Morgan Petcoke, L.P.; Arbitration in Houston, Texas
 
On August 12, 2010, Premcor filed a demand for arbitration against us and our subsidiary Kinder Morgan Petcoke, L.P., collectively referred to as Kinder Morgan, asserting claims for breach of contract.  Kinder Morgan performs certain petroleum coke handling operations at the Port Arthur, Texas refinery that is the subject of the claim.  The arbitration is being administered by the American Arbitration Association in Dallas, Texas.  Premcor alleges that Kinder Morgan breached its contract with Premcor by failing to name Premcor as an additional insured and failing to indemnify Premcor for claims brought against Premcor by PACC.  PACC and Premcor are affiliated companies.  PACC brought its claims against Premcor in a previous separate arbitration seeking to recover damages allegedly suffered by PACC when a pit wall of a coker unit collapsed at a refinery owned by Premcor.  PACC obtained an arbitration award against Premcor in the amount of $50.3 million, plus post-judgment interest.  Premcor is seeking to hold Kinder Morgan liable for the award. Premcor’s claim against Kinder Morgan is based in part upon Premcor’s allegation that Kinder Morgan is responsible to the extent of Kinder Morgan’s alleged proportionate fault in causing the pit wall collapse.  Kinder Morgan denies and is vigorously defending against all claims asserted by Premcor.  The final arbitration hearing is scheduled to begin on August 29, 2011.
 
Mine Safety Matters
 
In the first quarter of 2011, our bulk terminals operations that handle coal received ten citations under the Mine Safety and Health Act of 1977 which were deemed to be significant and substantial violations of mandatory health and safety standards under section 104 of the act (one of which was under section 104(d) of the act).  To date, the aggregate of proposed assessments received in respect of all citations received under the act in 2011 is $1,117.  We work to promptly abate violations described in the citations.  We do not believe any of such citations or the matters giving rise to such citations will have a material adverse impact on our business, financial position, results of operations or cash flows.
 
Employee Matters
 
James Lugliani vs. Kinder Morgan G.P., Inc. et al. in the Superior Court of California, Orange County
 
James Lugliani, a former Kinder Morgan employee, filed suit in January 2010 against various Kinder Morgan affiliates.  On behalf of himself and other similarly situated current and former employees, Mr. Lugliani claims that the Kinder Morgan defendants have violated the wage and hour provisions of the California Labor Code and Business & Professions Code by failing to provide meal and rest periods; failing to pay meal and rest period premiums; failing to pay all overtime wages due; failing to timely pay wages; failing to pay wages for vacation, holidays and other paid time off; and failing to keep proper payroll records.  We intend to vigorously defend the case.
 
Pipeline Integrity and Releases
 
From time to time, despite our best efforts, our pipelines experience leaks and ruptures.  These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property and/or personal injury or death.  In connection with these incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines.  Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.
 
Barstow, California
 
The United States Department of the Navy has alleged that historic releases of methyl tertiary-butyl ether, or MTBE, from Calnev’s Barstow terminal (i) have migrated underneath the Navy’s Marine Corps Logistics Base in Barstow; (ii) have impacted the Navy’s existing groundwater treatment system for unrelated groundwater contamination not alleged to have been caused by Calnev; and (iii) could affect the Barstow, California Marine Corps Logistic Base’s water supply system.  Although Calnev believes that it has meritorious defenses to the Navy’s claims, it is working with the Navy to agree upon an Administrative Settlement Agreement and Order on Consent for federal Comprehensive Environmental Response, Compensation and Liability Act (referred to as CERCLA) Removal Action to reimburse the Navy for $0.5 million in past response actions. 
 
Westridge Release, Burnaby, British Columbia
 
On July 24, 2007, a third-party contractor installing a sewer line for the City of Burnaby struck a crude oil pipeline segment included within our Trans Mountain pipeline system near its Westridge terminal in Burnaby, British Columbia, resulting in a release of approximately 1,400 barrels of crude oil.  The release impacted the surrounding neighborhood, several homes and nearby Burrard Inlet.  No injuries were reported.  To address the release, we initiated a comprehensive emergency response in collaboration with, among others, the City of Burnaby, the British Columbia Ministry of Environment, the National Energy Board (Canada), and the National Transportation Safety Board (Canada).  Cleanup and environmental remediation is complete, and we have received a British Columbia Ministry of Environment Certificate of Compliance confirming complete remediation.
 
Kinder Morgan Canada, Inc. commenced a lawsuit against the parties it believes were responsible for the third party strike, and a number of other parties have commenced related actions.  All of the outstanding litigation was settled without assignment of fault on April 8, 2011.  Kinder Morgan Canada has recovered the majority of its expended costs in responding to the third party strike.
 
On July 22, 2009, the British Columbia Ministry of Environment issued regulatory charges against the third-party contractor, the engineering consultant to the sewer line project, Kinder Morgan Canada Inc., and our subsidiary Trans Mountain L.P.  The British Columbia Ministry of Environment claims that the parties charged caused the release of crude oil, and in doing so were in violation of various sections of the Environmental, Fisheries and Migratory Bird Act.  A trial has been scheduled to commence in October 2011. We are of the view that the charges have been improperly laid against us, and we continue to vigorously defend against them.
 
Rockies Express Pipeline LLC Indiana Construction Incident
 
In April 2009, Randy Gardner, an employee of Sheehan Pipeline Construction Company (a third-party contractor to Rockies Express and referred to in this note as Sheehan Construction) was fatally injured during construction activities being conducted under the supervision and control of Sheehan Construction.  The cause of the incident was investigated by Indiana OSHA, which issued a citation to Sheehan Construction.  Rockies Express was not cited in connection with the incident.
 
In August 2010, the estate of Mr. Gardner filed a wrongful death action against Rockies Express and several other parties in the Superior Court of Marion County, Indiana, at case number 49D111008CT036870.  The plaintiff alleges that the defendants were negligent in allegedly failing to provide a safe worksite, and seeks unspecified compensatory damages.  Rockies Express denies that it was in any way negligent or otherwise responsible for this incident, and intends to assert contractual claims for complete indemnification for any and all costs arising from this incident, including any costs related to this lawsuit, against third parties and their insurers.
 
General
 
Although no assurance can be given, we believe that we have meritorious defenses to the actions set forth in this note and, to the extent an assessment of the matter is possible, if it is probable that a liability has been incurred and the amount of loss can be reasonably estimated, we believe that we have established an adequate reserve to cover potential liability.
 
Additionally, although it is not possible to predict the ultimate outcomes, we also believe, based on our experiences to date and the reserves we have established, that the ultimate resolution of these matters will not have a material adverse impact on our business, financial position, results of operations or distributions to limited partners.  As of March 31, 2011 and December 31, 2010, we have recorded a total reserve for legal fees, transportation rate cases and other litigation liabilities in the amount of $106.0 million and $169.8 million, respectively.  The reserve is primarily related to various claims from regulatory proceedings arising from our West Coast products pipeline transportation rates, and the contingent amount is based on both the circumstances of probability and reasonability of dollar estimates.  The overall change in the reserve from December 31, 2010 includes a $63.0 million payment (for transportation rate settlements on our Pacific operations’ pipelines) in March 2011 that reduced the liability.  We regularly assess the likelihood of adverse outcomes resulting from these claims in order to determine the adequacy of our liability provision.
 
Environmental Matters
 
The City of Los Angeles v. Kinder Morgan Liquids Terminals, LLC, Shell Oil Company, Equilon Enterprises LLC;  California Superior Court, County of Los Angeles, Case No. NC041463.
 
KMLT is a defendant in a lawsuit filed in 2005 alleging claims for environmental cleanup costs at the former Los Angeles Marine Terminal in the Port of Los Angeles.  The lawsuit was stayed beginning in 2009 and remained stayed through the end of 2010.  A hearing was held on December 13, 2010 to hear the City’s motion to remove the litigation stay.   At the hearing, the judge denied the motion to lift the stay without prejudice. A full litigation stay is in effect until the next case management conference set for June 13, 2011. During the stay, the parties deemed responsible by the local regulatory agency have worked with that agency concerning the scope of the required cleanup and are now starting a sampling and testing program at the site. The local regulatory agency issued specific cleanup goals in early 2010, and two of those parties, including KMLT, have appealed those cleanup goals to the state agency.
 
Plaintiff’s Third Amended Complaint alleges that future environmental cleanup costs at the former terminal will exceed $10 million, and that the plaintiff’s past damages exceed $2 million.  No trial date has yet been set.
 
Exxon Mobil Corporation v. GATX Corporation, Kinder Morgan Liquids Terminals, LLC and ST Services, Inc.
 
On April 23, 2003, Exxon Mobil Corporation filed a complaint in the Superior Court of New Jersey, Gloucester County.  The lawsuit relates to environmental remediation obligations at a Paulsboro, New Jersey liquids terminal owned by ExxonMobil from the mid-1950s through November 1989, by GATX Terminals Corp. from 1989 through September 2000, and later owned by Support Terminals and Pacific Atlantic Terminals, LLC.  The terminal is now owned by Plains Products, and it too is a party to the lawsuit.
 
The complaint seeks any and all damages related to remediating all environmental contamination at the terminal, and, according to the New Jersey Spill Compensation and Control Act, treble damages may be available for actual dollars incorrectly spent by the successful party in the lawsuit.  The parties engaged in court ordered mediation in 2008 through 2009, which did not result in settlement.  The trial judge has issued a Case Management Order and the parties are actively engaged in discovery.
 
On June 25, 2007, the New Jersey Department of Environmental Protection, the Commissioner of the New Jersey Department of Environmental Protection and the Administrator of the New Jersey Spill Compensation Fund, referred to collectively as the plaintiffs, filed a complaint against ExxonMobil Corporation and KMLT, formerly known as GATX Terminals Corporation, alleging natural resource damages related to historic contamination at the Paulsboro terminal.  The complaint was filed in Gloucester County, New Jersey.  Both ExxonMobil and KMLT filed third party complaints against Support Terminals/Plains seeking to bring Support Terminals/Plains into the case.  Support Terminals/Plains filed motions to dismiss the third party complaints, which were denied.  Support Terminals/Plains is now joined in the case, and it filed an Answer denying all claims.  The court has consolidated the two cases.  All private parties and the state participated in two mediation conferences in 2010.
 
In December 2010, KMLT and Plains Products entered into an agreement in principle with the New Jersey Department of Environmental Protection for settlement of the state’s alleged natural resource damages claim. Currently, a Consent Judgment is being finalized subject to public notice and comment and court approval. The tentative natural resource damage settlement includes a monetary award of $1.1 million and a series of remediation and restoration activities at the terminal site.  KMLT and Plains Products have joint responsibility for this settlement.  Currently, KMLT and Plains Products are working on a settlement agreement that will determine each parties’ relative share of responsibility to the NJDEP under the Consent Judgment noted above. We anticipate a final Consent Judgment during second quarter 2011. The settlement with the state does not resolve the original complaint brought by Exxon Mobil. There is no trial date set.
 
Mission Valley Terminal Lawsuit
 
In August 2007, the City of San Diego, on its own behalf and purporting to act on behalf of the People of the State of California, filed a lawsuit against us and several affiliates seeking injunctive relief and unspecified damages allegedly resulting from hydrocarbon and MTBE impacted soils and groundwater beneath the City’s stadium property in San Diego arising from historic operations at the Mission Valley terminal facility.  The case was filed in the Superior Court of California, San Diego County, case number 37-2007-00073033-CU-OR-CTL.  On September 26, 2007, we removed the case to the United States District Court, Southern District of California, case number 07CV1883WCAB.  The City disclosed in discovery that it is seeking approximately $170 million in damages for alleged lost value/lost profit from the redevelopment of the City’s property and alleged lost use of the water resources underlying the property.  Later, in 2010, the City amended its initial disclosures to add claims for restoration of the site as well as a number of other claims that increased their claim for damages to approximately $365 million.
 
According to the Court’s most recent Case Management Order of January 6, 2011, the parties must complete all fact discovery by June 24, 2011 and all expert witness discovery by August 29, 2011. A mandatory settlement conference is set for July 6, 2011 and the trial is now set for March 13, 2012. We have been and will continue to aggressively defend this action.   This site has been, and currently is, under the regulatory oversight and order of the California Regional Water Quality Control Board. We continue to be in compliance with this agency order as we conduct an extensive remediation effort at the City’s stadium property site.
 
Kinder Morgan, EPA Section 114 Information Request
 
On January 8, 2010, Kinder Morgan Inc., on behalf of Natural Gas Pipeline Company of America LLC, Horizon Pipeline Company and Rockies Express Pipeline LLC, received a Clean Air Act Section 114 information request from the U.S. Environmental Protection Agency, Region V.  This information request requires that the three affiliated companies provide the EPA with air permit and various other information related to their natural gas pipeline compressor station operations in Illinois, Indiana, and Ohio.  The affiliated companies have responded to the request and believe the relevant natural gas compressor station operations are in substantial compliance with applicable air quality laws and regulations.
 
Notice of Proposed Debarment
 
In April 2011, we received Notices of Proposed Debarment from the United States Environmental Protection Agency’s Suspension and Debarment Division, referred to in this Note as the EPA SDD.  The Notices propose the debarment of Kinder Morgan Energy Partners, L.P., Kinder Morgan, Inc., Kinder Morgan G.P., Inc., and Kinder Morgan Management, LLC, along with four of our subsidiaries, from participation in future federal contracting and assistance activities.  The Notices allege that certain of the respondents’ past environmental violations indicate a lack of present responsibility warranting debarment.  Our objective is to fully comply with all applicable legal requirements and to operate our assets in accordance with our processes, procedures and compliance plans.  We are performing better than industry averages in our incident rates and in our safety performance, all of which is publicly reported on our website.  We take environmental compliance very seriously, and look forward to demonstrating our present responsibility to the EPA SDD through this administrative process and to resolving this matter in a cooperative fashion.  We do not anticipate that the resolution of this matter will have a material adverse impact on our business, financial position, results of operations or cash flows.
 
Other Environmental
 
We are subject to environmental cleanup and enforcement actions from time to time.  In particular, the CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs.  Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment.  Although we believe our operations are in substantial compliance with applicable environmental law and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and carbon dioxide field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities.  Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.
 
We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations.  As we receive notices of non-compliance, we negotiate and settle these matters.  We do not believe that these alleged violations will have a material adverse effect on our business.
 
We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under administrative orders or related state remediation programs.  We have established a reserve to address the costs associated with the cleanup.
 
In addition, we are involved with and have been identified as a potentially responsible party in several federal and state superfund sites.  Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable.  In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, natural gas liquids, natural gas and carbon dioxide.  See “—Pipeline Integrity and Releases” above for additional information with respect to ruptures and leaks from our pipelines.
 

 

 
 
Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note will not have a material adverse effect on our business, financial position, results of operations or cash flows.  However, we are not able to reasonably estimate when the eventual settlements of these claims will occur, and changing circumstances could cause these matters to have a material adverse impact.  As of March 31, 2011, we have accrued an environmental reserve of $74.2 million, and we believe that these pending environmental matters will not have a material adverse impact on our business, cash flows, financial position or results of operations.  In addition, as of March 31, 2011, we have recorded a receivable of $7.4 million for expected cost recoveries that have been deemed probable.  As of December 31, 2010, our environmental reserve totaled $74.7 million and our estimated receivable for environmental cost recoveries totaled $8.6 million.  Additionally, many factors may change in the future affecting our reserve estimates, such as (i) regulatory changes; (ii) groundwater and land use near our sites; and (iii) changes in cleanup technology.
 
Other
 
We are a defendant in various lawsuits arising from the day-to-day operations of our businesses.  Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves, that the ultimate resolution of such items will not have a material adverse impact on our business, financial position, results of operations or cash flows.
 
 
11.  Regulatory Matters
 
Natural Gas Pipeline Expansion Filings
 
Kinder Morgan Interstate Gas Transmission Pipeline – Franklin to Hastings Expansion Project
 
KMIGT has filed a prior notice request to expand and replace certain mainline pipeline facilities to create up to 10,000 dekatherms per day of firm transportation capacity to serve an ethanol plant located near Aurora, Nebraska.  The estimated cost of the proposed facilities is $18.6 million.  The project was constructed and went into service on April 14, 2011.
 
Trailblazer Pipeline - Order Rejecting Tariff Record and Denying Waiver
 
On April 28, 2011, the FERC issued an Order Rejecting Tariff Record and Denying Waiver in Trailblazer Pipeline Company LLC’s annual fuel tracker filing at Docket No. RP11-1939-000.  The order requires Trailblazer to make a compliance filing for its annual Expansion Fuel Adjustment Percentage (EFAP) pursuant to its tariff.  In the past two annual tracker filings, Trailblazer received authorization by the FERC to defer collection of its fuel deferred account until a future period by granting a waiver of various fuel tracker provisions.  In its most recent annual filing, Trailblazer again asked for tariff waivers that would defer the collection of its fuel deferred account to a future period, which the FERC denied.  The effect of the FERC denying Trailblazer’s request for the tariff waivers is that Trailblazer must file a revised EFAP that reflects a fuel rate that is required for Trailblazer to collect both its current and deferred fuel costs from shippers.  Certain shippers under their interpretation of their contracts have