10-Q 1 km-form10q_jun302010.htm FORM 10-Q QUARTERLY REPORT km-form10q_jun302010.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 June 30, 2010
 
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 [   ] 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 215,268,720 common units outstanding as of July 30, 2010.

 
1

 

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
TABLE OF CONTENTS

   
Page
Number
 
PART I.   FINANCIAL INFORMATION
 
     
Item 1.
Financial Statements (Unaudited)                                                                                                                            
3
 
Consolidated Statements of Income - Three and Six Months Ended June 30, 2010 and 2009
3
 
Consolidated Balance Sheets - June 30, 2010 and December 31, 2009                                                                                                                       
4
 
Consolidated Statements of Cash Flows - Six Months Ended June 30, 2010 and 2009
5
 
Notes to Consolidated Financial Statements                                                                                                                       
6
     
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
41
 
General and Basis of Presentation                                                                                                                       
41
 
Critical Accounting Policies and Estimates                                                                                                                       
42
 
Results of Operations                                                                                                                       
43
 
Financial Condition                                                                                                                       
56
 
Recent Accounting Pronouncements                                                                                                                       
63
 
Information Regarding Forward-Looking Statements                                                                                                                       
63
     
Item 3.
Quantitative and Qualitative Disclosures About Market Risk                                                                                                                            
65
     
Item 4.
Controls and Procedures                                                                                                                            
65
     
     
     
 
PART II.   OTHER INFORMATION
 
     
Item 1.
Legal Proceedings                                                                                                                            
66
     
Item 1A.
Risk Factors                                                                                                                            
66
     
Item 2.
Unregistered Sales of Equity Securities and Use of Proceeds                                                                                                                            
66
     
Item 3.
Defaults Upon Senior Securities
66
     
Item 4.
(Removed and Reserved)                                                                                                                            
66
     
Item 5.
Other Information                                                                                                                            
66
     
Item 6.
Exhibits                                                                                                                            
66
     
 
Signature                                                                                                                            
68
     


 
2

 

PART I.  FINANCIAL INFORMATION

Item 1.  Financial Statements.

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

   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Revenues
                       
Natural gas sales
  $ 848.1     $ 716.9     $ 1,865.6     $ 1,605.6  
Services
    751.7       652.1       1,490.2       1,313.5  
Product sales and other
    361.7       276.3       735.3       512.7  
Total Revenues
    1,961.5       1,645.3       4,091.1       3,431.8  
                                 
Operating Costs, Expenses and Other
                               
Gas purchases and other costs of sales
    848.0       709.6       1,864.6       1,575.3  
Operations and maintenance
    317.5       267.3       770.4       517.3  
Depreciation, depletion and amortization
    223.2       203.1       450.5       413.3  
General and administrative
    93.4       72.6       194.5       155.1  
Taxes, other than income taxes
    41.1       23.4       86.2       62.4  
Other expense (income)
    (5.3 )     (2.7 )     (6.6 )     (3.6 )
Total Operating Costs, Expenses and Other
    1,517.9       1,273.3       3,359.6       2,719.8  
                                 
Operating Income
    443.6       372.0       731.5       712.0  
                                 
Other Income (Expense)
                               
Earnings from equity investments
    55.2       41.9       101.9       80.1  
Amortization of excess cost of equity investments
    (1.5 )     (1.5 )     (2.9 )     (2.9 )
Interest, net
    (116.9 )     (96.0 )     (228.4 )     (193.2 )
Other, net
    (2.3 )     20.2       4.4       30.9  
Total Other Income (Expense)
    (65.5 )     (35.4 )     (125.0 )     (85.1 )
                                 
Income Before Income Taxes
    378.1       336.6       606.5       626.9  
                                 
Income Taxes
    (13.0 )     (8.0 )     (14.0 )     (31.5 )
                                 
Net Income
    365.1       328.6       592.5       595.4  
                                 
Net Income Attributable to Noncontrolling Interests
    (3.9 )     (4.8 )     (6.0 )     (7.7 )
                                 
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
  $ 361.2     $ 323.8     $ 586.5     $ 587.7  
                                 
Calculation of Limited Partners’ Interest in Net Income
                               
Attributable to Kinder Morgan Energy Partners, L.P.:
                               
Net Income Attributable to Kinder Morgan Energy Partners, L.P.
  $ 361.2     $ 323.8     $ 586.5     $ 587.7  
Less: General Partner’s Interest
    (92.5 )     (232.8 )     (341.7 )     (456.5 )
Limited Partners’ Interest in Net Income
  $ 268.7     $ 91.0     $ 244.8     $ 131.2  
                                 
Limited Partners’ Net Income per Unit
  $ 0.88     $ 0.33     $ 0.81     $ 0.48  
                                 
Weighted Average Number of Units Used in Computation of Limited Partners’ Net Income per Unit
    304.5       277.5       301.7       273.5  
                                 
Per Unit Cash Distribution Declared
  $ 1.09     $ 1.05     $ 2.16     $ 2.10  

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


 
3

 


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

   
June 30,
2010
   
December 31,
2009
 
   
(Unaudited)
       
ASSETS
           
Current assets
           
Cash and cash equivalents
  $ 143.1     $ 146.6  
Restricted deposits
    19.3       15.2  
Accounts, notes and interest receivable, net
    834.7       902.1  
Inventories
    101.5       71.9  
Gas in underground storage
    50.8       43.5  
Fair value of derivative contracts
    44.5       20.8  
Other current assets
    39.5       44.6  
Total current assets
    1,233.4       1,244.7  
                 
Property, plant and equipment, net
    14,308.2       14,153.8  
Investments
    3,855.4       2,845.2  
Notes receivable
    188.5       190.6  
Goodwill
    1,205.0       1,149.2  
Other intangibles, net
    315.5       218.7  
Fair value of derivative contracts
    544.4       279.8  
Deferred charges and other assets
    177.9       180.2  
Total Assets
  $ 21,828.3     $ 20,262.2  
                 
LIABILITIES AND PARTNERS’ CAPITAL
               
Current liabilities
               
Current portion of debt
  $ 1,571.1     $ 594.7  
Cash book overdrafts
    42.8       34.8  
Accounts payable
    564.0       614.8  
Accrued interest
    232.8       222.4  
Accrued taxes
    56.2       57.8  
Deferred revenues
    78.1       76.0  
Fair value of derivative contracts
    189.1       272.0  
Accrued other current liabilities
    145.9       145.1  
Total current liabilities
    2,880.0       2,017.6  
                 
Long-term liabilities and deferred credits
               
Long-term debt
               
Outstanding
    10,279.7       9,997.7  
Value of interest rate swaps
    737.5       332.5  
Total Long-term debt
    11,017.2       10,330.2  
Deferred income taxes
    221.3       216.8  
Fair value of derivative contracts
    150.3       460.1  
Other long-term liabilities and deferred credits
    453.3       513.4  
Total long-term liabilities and deferred credits
    11,842.1       11,520.5  
                 
Total Liabilities
    14,722.1       13,538.1  
                 
Commitments and contingencies (Notes 4 and 10)
               
Partners’ Capital
               
Common units
    4,305.4       4,057.9  
Class B units
    71.6       78.6  
i-units
    2,752.9       2,681.7  
General partner
    64.6       221.1  
Accumulated other comprehensive loss
    (171.4 )     (394.8 )
Total Kinder Morgan Energy Partners, L.P. partners’ capital
    7,023.1       6,644.5  
Noncontrolling interests
    83.1       79.6  
Total Partners’ Capital
    7,106.2       6,724.1  
Total Liabilities and Partners’ Capital
  $ 21,828.3     $ 20,262.2  

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

 
4

 

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

   
Six Months Ended
June 30,
 
   
2010
   
2009
 
Cash Flows From Operating Activities
           
Net Income
  $ 592.5     $ 595.4  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation, depletion and amortization
    450.5       413.3  
Amortization of excess cost of equity investments
    2.9       2.9  
Income from the allowance for equity funds used during construction
    (0.6 )     (20.3 )
Income from the sale or casualty of property, plant and equipment and other net assets
    (6.6 )     (3.6 )
Earnings from equity investments
    (101.9 )     (80.1 )
Distributions from equity investments
    101.9       100.3  
Proceeds from termination of interest rate swap agreements
    -       144.4  
Changes in components of working capital:
               
Accounts receivable
    62.9       184.5  
Inventories
    (29.7 )     (11.2 )
Other current assets
    (20.8 )     (68.2 )
Accounts payable
    (42.7 )     (278.4 )
Accrued interest
    10.3       21.2  
Accrued taxes
    (2.2 )     3.4  
Accrued liabilities
    (13.0 )     (24.3 )
Rate reparations, refunds and other litigation reserve adjustments
    (48.3 )     (15.5 )
Other, net
    (23.0 )     (27.0 )
Net Cash Provided by Operating Activities
    932.2       936.8  
                 
Cash Flows From Investing Activities
               
Acquisitions of investments
    (929.7 )     -  
Acquisitions of assets
    (218.1 )     (18.5 )
Repayments from customers
    -       109.6  
Capital expenditures
    (451.1 )     (796.6 )
Sale or casualty of property, plant and equipment, and other net assets net of removal costs
    22.5       (4.7 )
Investments in margin deposits
    (3.9 )     (24.9 )
Contributions to equity investments
    (180.9 )     (802.8 )
Distributions from equity investments in excess of cumulative earnings
    93.3       -  
Net Cash Used in Investing Activities
    (1,667.9 )     (1,537.9 )
                 
Cash Flows From Financing Activities
               
Issuance of debt
    4,709.5       3,237.1  
Payment of debt
    (3,443.0 )     (2,392.8 )
Repayments from related party
    1.3       2.5  
Debt issue costs
    (22.3 )     (5.6 )
Increase (Decrease) in cash book overdrafts
    8.1       (21.6 )
Proceeds from issuance of common units
    433.2       669.5  
Contributions from noncontrolling interests
    7.2       8.6  
Distributions to partners and noncontrolling interests:
               
Common units
    (439.5 )     (391.4 )
Class B units
    (11.3 )     (11.2 )
General Partner
    (498.2 )     (445.5 )
Noncontrolling interests
    (12.0 )     (10.8 )
Other, net
    -       (0.2 )
Net Cash Provided by Financing Activities
    733.0       638.6  
                 
Effect of Exchange Rate Changes on Cash and Cash Equivalents
    (0.8 )     2.5  
                 
(Decrease) Increase in Cash and Cash Equivalents
    (3.5 )     40.0  
Cash and Cash Equivalents, beginning of period
    146.6       62.5  
Cash and Cash Equivalents, end of period
  $ 143.1     $ 102.5  
                 
Noncash Investing and Financing Activities
               
Assets acquired by the assumption or incurrence of liabilities
  $ 8.1     $ 3.7  
Assets acquired by the issuance of common units
  $ 81.7     $ 5.0  
Supplemental Disclosures of Cash Flow Information
               
Cash paid during the period for interest (net of capitalized interest)
  $ 224.7     $ 205.5  
Cash paid during the period for income taxes
  $ 7.9     $ 8.2  

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

 
5

 

KINDER MORGAN ENERGY PARTNERS, L.P. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 G.P., Inc. and Kinder Morgan Management, LLC
 
Kinder Morgan, Inc., referred to as KMI in this report, is a Kansas corporation privately owned by investors led by Richard D. Kinder, Chairman and Chief Executive Officer of both Kinder Morgan G.P., Inc. (our general partner) and Kinder Morgan Management, LLC (our general partner’s delegate).  KMI has been privately owned since its merger with Kinder Morgan Holdco LLC on May 30, 2007.  This merger is referred to in this report as the going-private transaction and is described more fully in Note 1 to our consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2009, referred to in this report as our 2009 Form 10-K.
 
KMI indirectly owns all the common stock of our general partner.  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.
 
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.  More information on these entities and the delegation of control agreement is contained in our 2009 Form 10-K.
 
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 presentation 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 2009 Form 10-K.
 
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.
 

 
6

 

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 [FAS 128, paragraph 1] ] [ are made in accordance with the “Earnings per Share” Topic of the Codification.
 
 
2.  Acquisitions, Joint Ventures, and Divestitures
 
Acquisitions
 
USD Terminal Acquisition
 
On January 15, 2010, we acquired three ethanol handling train terminals from US Development Group LLC for an aggregate consideration of $200.8 million, consisting of $115.7 million in cash, $81.7 million in common units, and $3.4 million in assumed liabilities.  The three train terminals are located in Linden, New Jersey; Baltimore, Maryland; and Dallas, Texas.  As part of the transaction, we announced the formation of a venture with US Development Group LLC to optimize and coordinate customer access to the three acquired terminals, other ethanol terminal assets we already own and operate, and other terminal projects currently under development by both parties.  The acquisition complemented and expanded the ethanol and rail terminal operations we previously owned, and all of the acquired assets are included in our Terminals business segment.
 
Based on our measurement of fair market values for all of the identifiable tangible and intangible assets acquired and liabilities assumed on the acquisition date, we assigned $94.6 million of our combined purchase price to “Other intangibles, net” (representing customer relationships); $43.1 million to “Property, Plant and Equipment, net”; and a combined $5.1 million to “Other current assets” and “Deferred charges and other assets.”  The remaining $58.0 million of our purchase price represented the future economic benefits expected to be derived from the acquisition that was not assigned to other identifiable, separately recognizable assets acquired, and we recorded this amount as “Goodwill.”  We believe the primary items that generated the goodwill are the value of the synergies created between the acquired assets and our pre-existing ethanol handling assets, and our expected ability to grow the business by leveraging our pre-existing experience in ethanol handling operations.  We expect that the entire amount of goodwill will be deductible for tax purposes.  Furthermore, in the third quarter of 2010, we will make a final settlement with the seller for acquired working capital balances.
 
Slay Industries Terminal Acquisition
 
On March 5, 2010, we acquired certain bulk and liquids terminal assets from Slay Industries for an aggregate consideration of $101.6 million, consisting of $97.0 million in cash, assumed liabilities of $1.6 million, and an obligation to pay additional cash consideration of $3.0 million in years 2013 through 2019, contingent upon the purchased assets providing us an agreed-upon amount of earnings during the three years following the acquisition.  Including accrued interest, we expect to pay approximately $2.0 million of this contingent consideration in the first half of 2013.
 
The acquired assets include (i) a marine terminal located in Sauget, Illinois; (ii) a transload liquid operation located in Muscatine, Iowa; (iii) a liquid bulk terminal located in St. Louis, Missouri; and (iv) a warehousing distribution center located in St. Louis.  All of the acquired terminals have long-term contracts with large creditworthy shippers.  As part of the transaction, we and Slay Industries entered into joint venture agreements at both the Kellogg Dock coal bulk terminal, located in Modoc, Illinois, and at the newly created North Cahokia terminal, located in Sauget and which has approximately 175 acres of land ready for development.  All of the assets located in Sauget have access to the Mississippi River and are served by five rail carriers.  The acquisition complemented and expanded our pre-existing Midwest terminal operations by adding a diverse mix of liquid and bulk capabilities, and all of the acquired assets are included in our Terminals business segment.
 

 
7

 

Based on our measurement of fair market values for all of the identifiable tangible and intangible assets acquired and liabilities assumed, we assigned $67.9 million of our purchase price to “Property, Plant and Equipment, net”; $24.6 million to “Other intangibles, net” (representing customer contracts); and a combined $8.2 million to “Investments.”  We recorded the remaining $0.9 million of our combined purchase price as “Goodwill,” representing certain advantageous factors that contributed to our acquisition price exceeding the fair value of acquired identifiable net assets—in the aggregate, these factors represented goodwill, and we expect that the entire amount of goodwill will be deductible for tax purposes.
 
Mission Valley Terminal Acquisition
 
On March 1, 2010, we acquired the refined products terminal assets at Mission Valley, California from Equilon Enterprises LLC (d/b/a Shell Oil Products US) for $13.5 million in cash.  The acquired assets include buildings, equipment, delivery facilities (including two truck loading racks), and storage tanks with a total capacity of approximately 170,000 barrels for gasoline, diesel fuel and jet fuel.  The terminal operates under a long-term terminaling agreement with Tesoro Refining and Marketing Company.  We assigned our entire purchase price to “Property, Plant and Equipment, net.”  The acquisition enhanced our Pacific operations and complemented our existing West Coast terminal operations, and the acquired assets are included in our Products Pipelines business segment.
 
KinderHawk Field Services LLC Acquisition
 
On May 21, 2010, we completed our previously announced agreement to purchase a 50% ownership interest in Petrohawk Energy Corporation’s natural gas gathering and treating business in the Haynesville shale gas formation located in northwest Louisiana.  On that date, we paid an aggregate consideration of $921.4 million in cash for our 50% equity ownership interest, and pursuant to the provisions of the joint venture formation and contribution agreement, our payment included approximately $46.4 million for both estimated capital expenditures and estimated net cash outflows from operating activities for the period January 1, 2010 through May 21, 2010.
 
Petrohawk will continue to operate the business during a short transition period, and following the transition period, a newly formed company named KinderHawk Field Services LLC, owned 50% by us and 50% by Petrohawk, will assume the joint venture operations.  The joint venture assets consist of more than 200 miles of pipeline currently in service, and it is expected that the pipeline mileage will increase to approximately 375 miles with projected throughput of over 800 million cubic feet per day of natural gas by the end of 2010.  Additionally, it is expected that the system’s natural gas amine treating plants will have capacity of approximately 2,635 gallons per minute by the end of 2010.  The joint venture has also received a dedication to transport and treat all of Petrohawk’s operated Haynesville and Bossier shale gas production in northwest Louisiana for the life of the leases at agreed upon rates, as well as minimum volume commitments from Petrohawk for the first five years of the joint venture agreement.  It will also focus on providing transportation services to third-party producers.  The joint venture ultimately is expected to have approximately two billion cubic feet per day of throughput capacity, which will make it one of the largest gathering and treating systems in the United States.
 
The acquisition complemented and expanded our existing natural gas gathering and treating businesses, and we assigned our entire purchase price to “Investments” on our accompanying consolidated balance sheet as of June 30, 2010. Our investment and our pro rata share of the joint venture’s operating results are included as part of our Natural Gas Pipelines business segment.
 
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, 2009 as if they had occurred as of January 1, 2009 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.
 

 
8

 

Acquisitions Subsequent to June 30, 2010
 
On July 22, 2010, we acquired a terminal with ethanol tanks, a truck rack and additional acreage in Dallas, Texas, from Direct Fuels Partners, L.P. for an aggregate consideration of $16 million, consisting of $15.9 million in cash and an assumed property tax liability of $0.1 million.  The acquired terminal facility is connected to the Dallas, Texas unit train terminal we acquired from USD Development Group LLC in January 2010 (described above in “Acquisitions—USD Terminal Acquisition).
 
Joint Ventures
 
Joint Venture Formations and Ownership Changes
 
Eagle Ford Gathering LLC
 
On May 14, 2010, we and Copano Energy, L.L.C. entered into formal agreements for a joint venture to provide natural gas gathering, transportation and processing services to natural gas producers in the Eagle Ford Shale formation in south Texas.  The joint venture is named Eagle Ford Gathering LLC, and as previously announced in November 2009, we will own 50% of the equity in the project (a 50% member interest in Eagle Ford Gathering LLC), and Copano will own the remaining 50% interest.  Copano will serve as operator and managing member of Eagle Ford Gathering LLC.  We and Copano have committed approximately 375 million cubic feet per day of natural gas capacity to the joint venture through 2024 for both transportation on our natural gas pipeline that extends from Laredo to Katy, Texas, and for processing at Copano’s natural gas processing plant located in Colorado County, Texas.
 
On July 6, 2010, Eagle Ford Gathering LLC announced the execution of a definitive long-term, fee-based gas services agreement with SM Energy Company.  According to the provisions of the agreement (i) SM Energy will commit Eagle Ford production from its assets located in LaSalle, Dimmitt, and Webb Counties, Texas up to a maximum level of 200 million cubic feet per day over a ten year term; and (ii) Eagle Ford Gathering LLC will construct approximately 85-miles of 24-inch and 30-inch diameter pipeline to serve SM Energy’s acreage in the western Eagle Ford Shale formation to our Freer compressor station located in Duval County, Texas.  The pipeline is expected to begin service during the summer of 2011.
 
Combined, we and Copano will invest approximately $137 million for the first phase of construction, which will significantly extend the natural gas gathering pipeline beyond the length previously announced in November 2009.  As of June 30, 2010, our capital contributions (and net equity investment) in Eagle Ford Gathering LLC totaled $0.1 million.
 
Midcontinent Express Pipeline LLC
 
On May 26, 2010, Energy Transfer Partners, L.P. transferred to Regency Energy Partners LP (i) a 49.9% ownership interest in Midcontinent Express Pipeline LLC; and (ii) a one-time right to purchase its remaining 0.1% ownership interest in Midcontinent Express Pipeline LLC on May 26, 2011.  As a result of this transfer, Energy Transfer Partners, L.P. now owns a 0.1% ownership interest in Midcontinent Express Pipeline LLC.  Our subsidiary, Kinder Morgan Operating L.P.,  “A,” owns the remaining 50% ownership interest in Midcontinent Express Pipeline LLC, and we did not record any equity method adjustments as a result of the ownership change between Regency Energy Partners LP and Energy Transfer Partners, L.P.
 
Joint Venture Contributions
 
During the three and six months ended June 30, 2010, we contributed $45.3 million and $180.9 million, respectively, to our equity investees.  Our combined contributions to equity investees during the first half of 2010 included contributions of $130.5 million to Rockies Express Pipeline LLC and contributions of $39.0 million to Midcontinent Express Pipeline LLC.
 
During the three and six months ended June 30, 2009, we contributed $629.3 million and $802.8 million, respectively, to our equity investees.  Our 2009 contributions were paid primarily to West2East Pipeline LLC, Midcontinent Express Pipeline LLC, and Fayetteville Express Pipeline LLC to partially fund their respective Rockies Express, Midcontinent Express, and Fayetteville Express natural gas pipeline system construction and/or pre-construction costs.  We own a 50% equity interest in Fayetteville Express Pipeline LLC.  We report our equity contributions separately as “Contributions to equity investments” in our accompanying consolidated statements of cash flows for the six months ended June 30, 2010 and 2009.
 

 
9

 

Divestitures
 
Cypress Pipeline
 
On July 14, 2009, we received notice from Westlake Petrochemicals LLC, a wholly-owned subsidiary of Westlake Chemical Corporation, that it was exercising an option it held to purchase a 50% ownership interest in our Cypress Pipeline.  We expect the transaction to close by the end of the third quarter of 2010.  As of June 30, 2010, the net assets of our Cypress Pipeline totaled approximately $20.6 million.  At the time of the sale, we will (i) deconsolidate the net assets of the Cypress Pipeline; (ii) recognize a gain or loss on the sale of net assets equal to the difference between (a) the proceeds received from the sale, and (b) 50% of the net assets’ carrying value; and (iii) recognize the remaining 50% noncontrolling investment retained at its fair value (which is expected to result in a gain).
 
 
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 six months ended June 30, 2010 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     $ 266.9     $ 613.1     $ 1,526.3  
Accumulated impairment losses(a)
    -       -       -       -       (377.1 )     (377.1 )
Balance as of December 31, 2009
    263.2       337.0       46.1       266.9       236.0       1,149.2  
Acquisitions
    -       -       -       58.9       -       58.9  
Currency translation adjustments
    -       -       -       -       (3.1 )     (3.1 )
Balance as of June 30, 2010
  $ 263.2     $ 337.0     $ 46.1     $ 325.8     $ 232.9     $ 1,205.0  
__________

(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.
 
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 six months of 2010, and as of both June 30, 2010 and December 31, 2009, we reported $138.2 million in equity method goodwill within the caption “Investments” in our accompanying consolidated balance sheets.
 

 
10

 

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):
 
   
June 30,
2010
   
December 31,
2009
 
Customer relationships, contracts and agreements
           
Gross carrying amount
  $ 392.2     $ 273.0  
Accumulated amortization
    (89.2 )     (67.1 )
Net carrying amount
    303.0       205.9  
                 
Technology-based assets, lease value and other
               
Gross carrying amount
    15.7       15.7  
Accumulated amortization
    (3.2 )     (2.9 )
Net carrying amount
    12.5       12.8  
                 
Total Other intangibles, net
  $ 315.5     $ 218.7  
 
The increase in the carrying amount of our customer relationships, contracts and agreements since December 31, 2009 was mainly due to the acquisition of intangibles included in our purchase of terminal assets from US Development Group LLC and Slay Industries, discussed in Note 2.
 
We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives.  Among the factors we weigh, depending on the nature of the asset, are the effects of obsolescence, new technology, and competition.  For the three and six months ended June 30, 2010, the amortization expense on our intangibles totaled $11.1 million and $22.4 million, respectively, and for the same prior year periods, the amortization expense on our intangibles totaled $3.4 million and $6.9 million, respectively.  As of June 30, 2010, the weighted average amortization period for our intangible assets was approximately 14 years, and our estimated amortization expense for these assets for each of the next five fiscal years (2011 – 2015) is approximately $38.7 million, $33.3 million, $29.4 million, $26.1 million and $23.2 million, respectively.
 
 
4.  Debt
 
We classify our debt based on the contractual maturity dates of the underlying debt instruments or as of the earliest put date available to the holders of the applicable debt.  We defer costs associated with debt issuance over the applicable term or to the first put date, in the case of debt with a put feature.  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 June 30, 2010 and December 31, 2009 was $11,850.8 million and $10,592.4 million, respectively.  The weighted average interest rate on all of our borrowings (both short-term and long-term) was approximately 4.33% during the second quarter of 2010 and approximately 4.57% during the second quarter of 2009.  For the first six months of 2010 and 2009, the weighted average interest rate on all of our borrowings (both short and long term) was approximately 4.33% and 4.82%, respectively.
 
Our outstanding short-term debt as of June 30, 2010 was $1,571.1 million.  The balance consisted of (i) $700.0 million in principal amount of 6.75% senior notes due March 15, 2011 (including discount, the notes had a carrying amount of $699.9 million as of June 30, 2010); (ii) $501.4 million of commercial paper borrowings; (iii) $250.0 million in principal amount of 7.50% senior notes due November 1, 2010 (including discount, the notes had a carrying amount of $249.9 million as of June 30, 2010); (iv) $75.0 million in outstanding borrowings under our unsecured revolving bank credit facility (discussed following); (v) $23.7 million in principal amount of tax-exempt bonds that mature on April 1, 2024, but are due on demand pursuant to certain standby purchase agreement provisions contained in the bond indenture (our subsidiary Kinder Morgan Operating L.P. “B” is the obligor on the bonds); (vi) a $9.1 million portion of a 5.40% long-term note payable (our subsidiaries Kinder Morgan Operating L.P. “A” and Kinder Morgan Canada Company are the obligors on the note); (vii) a $7.1 million portion of 5.23% long-term senior notes (our subsidiary Kinder Morgan Texas Pipeline, L.P. is the obligor on the notes); and (viii) $5.0 million in principal amount of 6.00% Development Revenue Bonds due January 1, 2011 and issued by the Louisiana Community Development Authority, a political subdivision of the state of Louisiana (our subsidiary Kinder Morgan Louisiana Pipeline LLC is the obligor on the bonds).
 

 
11

 

Credit Facility
 
As of March 31, 2010, we had a $1.79 billion five-year unsecured revolving bank credit facility that was due August 18, 2010.  On June 23, 2010, we successfully renegotiated this credit facility, replacing it with a new $2.0 billion three-year, senior unsecured revolving credit facility that expires June 23, 2013.  The covenants of this credit facility are substantially similar to the terms of our previous facility; however, the interest rates for borrowings under this facility have increased from our previous facility.
 
Similar to our previous facility, our $2.0 billion credit facility is with a syndicate of financial institutions, and the facility permits us to obtain bids for fixed rate loans from members of the lending syndicate.  Wells Fargo Bank, National Association is the administrative agent, and borrowings under the credit facility can be used for general partnership purposes and as a backup for our commercial paper program.  Interest on the credit facility accrues at our option at a floating rate equal to either (i) the administrative agent’s base rate (but not less than the Federal Funds Rate, plus 0.5%); or (ii) LIBOR, plus a margin, which varies depending upon the credit rating of our long-term senior unsecured debt.  The credit facility can be amended to allow for borrowings of up to $2.3 billion.
 
The outstanding balance under our $2.0 billion credit facility was $75.0 million as of June 30, 2010, and the weighted average interest rate on these borrowings was 2.10%.  As of December 31, 2009, the outstanding balance under our previous $1.79 billion credit facility was $300 million, and the weighted average interest rate on these borrowings was 0.59%.
 
Additionally, as of June 30, 2010, the amount available for borrowing under our credit facility was reduced by a combined amount of $723.6 million, consisting of $501.4 million of commercial paper borrowings and $222.2 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 $89.4 million in three letters of credit that support tax-exempt bonds; (iii) a $16.1 million letter of credit that supports our indemnification obligations on the Series D note borrowings of Cortez Capital Corporation; and (iv) a combined $16.7 million in other letters of credit supporting other obligations of us and our subsidiaries.
 
Commercial Paper Program
 
On October 13, 2008, Standard & Poor’s Ratings Services lowered our short-term credit rating to A-3 from A-2, and on May 6, 2009, Moody’s Investors Service, Inc. downgraded our commercial paper rating to Prime-3 from Prime-2 and assigned a negative outlook to our long-term credit rating.  As a result of these revisions and the commercial paper market conditions, we were unable to access commercial paper borrowings throughout 2009.
 
However, on February 25, 2010, Standard & Poor’s revised its outlook on our long-term credit rating to stable from negative, affirmed our long-term credit rating at BBB, and raised our short-term credit rating to A-2 from A-3.  The rating agency’s revisions reflected its expectations that our financial profile will improve due to lower guaranteed debt obligations and higher expected cash flows associated with the completion and start-up of our 50%-owned Rockies Express and Midcontinent Express natural gas pipeline systems and our fully-owned Kinder Morgan Louisiana natural gas pipeline system.  Due to this favorable change in our short-term credit rating, we resumed issuing commercial paper in March 2010, and as of June 30, 2010, we had $501.4 million of commercial paper outstanding with an average interest rate of approximately 0.67%.  In the near term, we expect that our short-term liquidity and financing needs will be met through a combination of borrowings made under our bank credit facility and our commercial paper program.
 
Senior Notes
 
On May 19, 2010, we completed a public offering of senior notes.  We issued a total of $1 billion in principal amount of senior notes in two separate series, consisting of $600 million of 5.30% notes due September 15, 2020, and $400 million of 6.55% notes due September 15, 2040.  We received proceeds from the issuance of the notes, after underwriting discounts and commissions, of $993.1 million, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.
 

 
12

 

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.  The following is a description of our contingent debt agreements as of June 30, 2010.
 
Cortez Pipeline Company Debt
 
Pursuant to a Throughput and Deficiency Agreement, the partners of Cortez Pipeline Company (our subsidiary Kinder Morgan CO2 Company, L.P. – 50% partner; a subsidiary of Exxon Mobil Corporation – 37% partner; and Cortez Vickers Pipeline Company – 13% partner) are required, on a several, proportional percentage ownership basis, to contribute capital to Cortez Pipeline Company in the event of a cash deficiency.  Furthermore, due to our indirect ownership of Cortez Pipeline Company through Kinder Morgan CO2 Company, L.P., we severally guarantee 50% of the debt of Cortez Capital Corporation, a wholly-owned subsidiary of Cortez Pipeline Company.
 
As of June 30, 2010, the debt facilities of Cortez Capital Corporation consisted of (i) $32.1 million of fixed rate Series D notes due May 15, 2013; (ii) $100 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) a $40 million committed revolving credit facility also due December 11, 2012.  As of June 30, 2010, in addition to the outstanding Series D and Series E notes, Cortez Capital Corporation had outstanding borrowings of $11.8 million under its credit facility.  Accordingly, as of June 30, 2010, our contingent share of Cortez’s debt was $72.0 million (50% of total borrowings).
 
With respect to Cortez’s Series D notes, the average interest rate on the notes is 7.14%, and the outstanding $32.1 million principal amount of the notes is due in three equal annual installments of $10.7 million beginning May 2011.  Shell Oil Company shares our guaranty obligations jointly and severally; however, we are obligated to indemnify Shell for liabilities it incurs in connection with such guaranty.  Accordingly, as of June 30, 2010, JP Morgan Chase has issued a letter of credit on our behalf in the amount of $16.1 million to secure our indemnification obligations to Shell for 50% of the $32.1 million in principal amount of Series D notes outstanding as of that date.
 
Nassau County, Florida Ocean Highway and Port Authority Debt
 
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 June 30, 2010, this letter of credit had a face amount of $19.8 million.
 
Fayetteville Express Pipeline LLC Debt
 
Fayetteville Express Pipeline LLC is an equity method investee of ours, and pursuant to certain guaranty agreements with Fayetteville Express Pipeline LLC, both of the member owners of Fayetteville Express Pipeline LLC have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Fayetteville Express, borrowings under its $1.1 billion, unsecured revolving credit facility that is due May 11, 2012.  The two member owners and their respective ownership interests consist of the following: our subsidiary Kinder Morgan Operating L.P. “A” – 50%; and Energy Transfer Partners, L.P. – 50%.
 
The Fayetteville Express Pipeline LLC credit facility is with a syndicate of financial institutions with The Royal Bank of Scotland plc as the administrative agent.  Borrowings under the credit facility are primarily used to finance the construction of the Fayetteville Express natural gas pipeline system and to pay related expenses.  As of June 30, 2010, Fayetteville Express had outstanding borrowings of $663.0 million under its bank credit facility.  Accordingly, as of June 30, 2010, our contingent share of Fayetteville Express’ debt was $331.5 million (50% of total borrowings).
 

 
13

 

Midcontinent Express Pipeline LLC Debt
 
Midcontinent Express Pipeline LLC is also an equity method investee of ours, and the three member owners and their respective ownership interests consist of the following: our subsidiary Kinder Morgan Operating L.P. “A” – 50%; Regency Energy Partners, L.P. – 49.9%; and Energy Transfer Partners, L.P. – 0.1%.  Pursuant to certain guaranty agreements, each of the member owners of Midcontinent Express Pipeline LLC have agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Midcontinent Express Pipeline LLC, borrowings under its three-year, unsecured revolving credit facility due February 28, 2011.  The facility is with a syndicate of financial institutions with The Royal Bank of Scotland plc as the administrative agent.  Borrowings under the credit facility can be used for general limited liability company purposes.
 
As of March 31, 2010, the credit facility allowed for borrowings up to $255.4 million.  On April 30, 2010, Midcontinent Express Pipeline LLC amended its bank credit facility to allow for borrowings up to $175.4 million (a reduction from $255.4 million), and as of June 30, 2010, Midcontinent Express Pipeline LLC had outstanding borrowings of $33.1 million under its bank credit facility.  Accordingly, as of June 30, 2010, our contingent share of Midcontinent Express’ debt was $16.6 million (50% of total guaranteed borrowings).  Furthermore, the credit facility can be used for the issuance of letters of credit to support the operation of the Midcontinent Express pipeline system, and as of June 30, 2010, a letter of credit having a face amount of $33.3 million was issued under the credit facility by the Bank of Tokyo-Mitsubishi UFJ, Ltd.  Accordingly, as of June 30, 2010, our contingent responsibility with regard to this outstanding letter of credit was $16.7 million (50% of total face amount).
 
Rockies Express Pipeline LLC Debt
 
Rockies Express Pipeline LLC is another equity method investee of ours, and pursuant to certain guaranty agreements remaining in effect on March 31, 2010, all three member owners of Rockies Express Pipeline LLC had agreed to guarantee, severally in the same proportion as their percentage ownership of the member interests in Rockies Express Pipeline LLC, borrowings under its $2.0 billion five-year, unsecured revolving bank credit facility due April 28, 2011.  The three member owners and their respective ownership interests consist of the following: our subsidiary Kinder Morgan W2E Pipeline LLC – 50%; a subsidiary of Sempra Energy – 25%; and a subsidiary of ConocoPhillips – 25%.
 
As of March 31, 2010, Rockies Express Pipeline LLC had no outstanding borrowings under its bank credit facility; therefore, we had no contingent debt obligation associated with our guaranty agreement.  On April 8, 2010, Rockies Express Pipeline LLC amended its bank credit facility to allow for borrowings up to $200 million (a reduction from $2.0 billion), and on this same date, each of its three member owners were released from their respective debt obligations under the previous guaranty agreements.  Accordingly, we no longer have a contingent debt obligation with respect to Rockies 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 2009 Form 10-K.
 
5.  Partners’ Capital
 
Limited Partner Units
 
As of June 30, 2010 and December 31, 2009, our partners’ capital included the following limited partner units:
 
   
June 30,
   
December 31,
 
   
2010
   
2009
 
Common units
    214,053,605       206,020,826  
Class B units
    5,313,400       5,313,400  
i-units
    88,670,863       85,538,263  
Total limited partner units
    308,037,868       296,872,489  
 
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.
 

 
14

 

As of June 30, 2010, our total common units consisted of 197,683,177 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, 2009, our total common units consisted of 189,650,398 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 June 30, 2010 and December 31, 2009, 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 June 30, 2010 and December 31, 2009, all of our i-units were held by KMR.  Our i-units are a separate class of limited partner interests in us and are not publicly traded.  The number of i-units we distribute to KMR is based upon the amount of cash we distribute to the owners of our common units.  When cash is paid to the holders of our common units, we issue additional i-units to KMR.  The fraction of an i-unit paid per i-unit owned by KMR will have a value based on the cash payment on the common units.
 
Changes in Partners’ Capital
 
For each of the three and six month periods ended June 30, 2010 and 2009, 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 June 30,
 
   
2010
   
2009
 
   
KMP
   
Noncontrolling
interests
   
Total
   
KMP
   
Noncontrolling interests
   
Total
 
                                     
Beginning Balance
  $ 6,612.6     $ 78.7     $ 6,691.3     $ 6,145.5     $ 71.6     $ 6,217.1  
                                                 
Units issued as consideration in the acquisition of assets
    -       -       -       5.0       -       5.0  
Units issued for cash
    433.1       -       433.1       381.6       -       381.6  
Distributions paid in cash
    (480.2 )     (6.0 )     (486.2 )     (430.8 )     (5.4 )     (436.2 )
Adjustments to capital resulting from related party acquisitions
    -       -       -       20.2       0.3       20.5  
KMI going-private transaction
expenses
    1.3       -       1.3       1.4       -       1.4  
Cash contributions
    -       5.5       5.5       -       4.8       4.8  
Other adjustments
    -       -       -       (0.2 )     -       (0.2 )
                                                 
Comprehensive income:
                                               
Net Income
    361.2       3.9       365.1       323.8       4.8       328.6  
Other comprehensive income (loss):
                                               
Change in fair value of derivatives  utilized for hedging purposes
    141.6       1.5       143.1       (336.1 )     (3.4 )     (339.5 )
Reclassification of change in fair
value of derivatives to  net
income
    39.1       0.4       39.5       30.3       0.3       30.6  
Foreign currency translation
adjustments
    (85.5 )     (0.9 )     (86.4 )     127.1       1.3       128.4  
Adjustments to pension and other postretirement benefit plan
liabilities
    (0.1 )     -       (0.1 )     (0.1 )     -       (0.1 )
Total other comprehensive income
(loss)
    95.1       1.0       96.1       (178.8 )     (1.8 )     (180.6 )
Comprehensive income
    456.3       4.9       461.2       145.0       3.0       148.0  
                                                 
Ending Balance
  $ 7,023.1     $ 83.1     $ 7,106.2     $ 6,267.7     $ 74.3     $ 6,342.0  
____________
 

 
15

 


 
   
Six Months Ended June 30,
 
   
2010
   
2009
 
   
KMP
   
Noncontrolling
interests
   
Total
   
KMP
   
Noncontrolling interests
   
Total
 
                                     
Beginning Balance
  $ 6,644.5     $ 79.6     $ 6,724.1     $ 6,045.6     $ 70.7     $ 6,116.3  
                                                 
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       5.0       -       5.0  
Units issued for cash
    433.1       -       433.1       669.2       -       669.2  
Distributions paid in cash
    (949.0 )     (12.0 )     (961.0 )     (848.1 )     (10.8 )     (858.9 )
Adjustments to capital resulting from related party acquisitions
    -       -       -       22.9       0.3       23.2  
KMI going-private transaction
expenses
    2.7       -       2.7       2.8       -       2.8  
Cash contributions
    -       7.2       7.2       -       8.6       8.6  
Other adjustments
    -       -       -       (0.2 )     -       (0.2 )
                                                 
Comprehensive income:
                                               
Net Income
    586.5       6.0       592.5       587.7       7.7       595.4  
Other comprehensive income (loss):
                                               
Change in fair value of derivatives
utilized for hedging purposes
    166.0       1.7       167.7       (300.6 )     (3.0 )     (303.6 )
Reclassification of change in fair
value of derivatives to  net
income
    86.1       0.9       87.0       13.2       0.1       13.3  
Foreign currency translation
adjustments
    (26.3 )     (0.3 )     (26.6 )     72.9       0.7       73.6  
Adjustments to pension and other postretirement benefit plan
liabilities
    (2.4 )     -       (2.4 )     (2.9 )     -       (2.9 )
Total other comprehensive income
(loss)
    223.4       2.3       225.7       (217.4 )     (2.2 )     (219.6 )
Comprehensive income
    809.9       8.3       818.2       370.3       5.5       375.8  
                                                 
Ending Balance
  $ 7,023.1     $ 83.1     $ 7,106.2     $ 6,267.7     $ 74.3     $ 6,342.0  
 
During the first six months of both 2010 and 2009, there were no material changes in our ownership interests in subsidiaries in which we retained a controlling financial interest.
 
Equity Issuances
 
On January 15, 2010, we issued 1,287,287 common units as part of our purchase price for the ethanol handling terminal assets we acquired from US Development Group LLC.  We valued the common units at $81.7 million, determining the units’ value based on the $63.45 closing market price of the common units on the New York Stock Exchange on the January 15, 2010 acquisition date.  For more information on this acquisition, see Note 2 “Acquisitions, Joint Ventures, and Divestitures—Acquisitions—USD Terminal Acquisition.”
 
On May 7, 2010, we issued, in a public offering, 6,500,000 of our common units at a price of $66.25 per unit, less commissions and underwriting expenses.  After commissions and underwriting expenses, we received net proceeds of $417.4 million for the issuance of these 6,500,000 common units, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.
 
In June 2010, we issued 243,042 of our common units pursuant to our equity distribution agreement with UBS Securities LLC (UBS).  After commissions of $0.1 million, we received net proceeds from the issuance of these common units of $15.8 million, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.  Our equity distribution agreement provides us the right, but not the obligation, to sell common units in the future, at prices we deem appropriate.  We retain at all times complete control over the amount and the timing of each sale, and we will designate the maximum number of common units to be sold through UBS, on a daily basis or otherwise as we and UBS agree.  Either we or UBS may suspend the offering of common units pursuant to the agreement by notifying the other party.  For additional information regarding our equity distribution agreement, see Note 9 to our consolidated financial statements included in our 2009 Form 10-K.
 

 
16

 

Equity Issuances Subsequent to June 30, 2010
 
On July 1, 2010, we issued 47,800 of our common units for the settlement of sales made before June 30, 2010 pursuant to our equity distribution agreement.  After commissions of $0.1 million, we received net proceeds of $3.1 million for the issuance of these 47,800 common units, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.
 
Also, on July 2, 2010, we completed an offering of 1,167,315 of our common units at a price of $64.25 per unit in a privately negotiated transaction.  We received net proceeds of $75.0 million for the issuance of these 1,167,315 common units, and we used the proceeds to reduce the borrowings under our commercial paper program and our bank credit facility.
 
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.
 
On May 14, 2010, we paid a cash distribution of $1.07 per unit to our common unitholders and our Class B unitholders for the quarterly period ended March 31, 2010.  KMR, our sole i-unitholder, received a distribution of 1,556,130 i-units from us on May 14, 2010, based on the $1.07 per unit distributed to our common unitholders on that date.  The distributions were declared on April 21, 2010, payable to unitholders of record as of April 30, 2010.
 
Incentive distributions allocated to our general partner are determined by the amount quarterly distributions to unitholders exceed certain specified target levels, according to the provisions of our partnership agreement.  Our distribution of $1.07 per unit paid on May 14, 2010 for the first quarter of 2010 required an incentive distribution to our general partner of $249.4 million.  Our distribution of $1.05 per unit paid on May 15, 2009 for the first quarter of 2009 resulted in an incentive distribution payment to our general partner in the amount of $223.2 million.  The increased incentive distribution to our general partner paid for the first quarter of 2010 over the incentive distribution paid for the first quarter of 2009 reflects the increase in the amount distributed per unit as well as the issuance of additional units.
 
Subsequent Event
 
On July 21, 2010, we declared a cash distribution of $1.09 per unit for the quarterly period ended June 30, 2010.  The distribution will be paid on August 13, 2010, to unitholders of record as of July 30, 2010.  Our common unitholders and Class B unitholders will receive cash.  KMR will receive a distribution of 1,625,869 additional i-units based on the $1.09 distribution per common unit.  For each outstanding i-unit that KMR holds, a fraction of an i-unit (0.018336) will be issued.  This fraction was determined by dividing:
 
▪ $1.09, the cash amount distributed per common unit
 
by
 
▪ $59.446, the average of KMR’s shares’ closing market prices from July 14-27, 2010, 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 second quarter of 2010 of $1.09 per unit will result in an incentive distribution to our general partner of $89.8 million.  This compares to our distribution of $1.05 per unit and incentive distribution to our general partner of $231.8 million for the second quarter of 2009.  Under the terms of our partnership agreement, our declared distributions to unitholders for the second quarter of 2010 required incentive distributions to our general partner in the amount of $263.4 million.  However, our general partner’s incentive distribution was reduced by a combined
 

 
17

 

$173.6 million, including (i) a waived incentive amount equal to $5.3 million related to equity issued to finance our acquisition of a 50% interest in Petrohawk Energy Corporation’s natural gas gathering and treating business (described in Note 2); and (ii) a reduced incentive amount of $168.3 million (including its 2% general partner’s interest, total cash distributions were reduced $170.0 million), due to a portion of our cash distributions for the second quarter of 2010 being a distribution of cash from interim capital transactions (ICT Distribution), rather than a distribution of cash from operations. As provided in our partnership agreement, our general partner receives no incentive distribution on ICT Distributions.
 
 
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 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), is recognized in earnings during the current period.  The effectiveness of hedges using an option contract may be assessed based on changes in the option’s intrinsic value with the change in the time value of the contract being excluded from the assessment of hedge effectiveness.  Changes in the excluded component of the change in an option’s time value are included currently in earnings.  During the three and six months ended June 30, 2010, we recognized net gains of $7.8 million and $14.1 million, respectively, related to crude oil and natural gas hedges and resulting from hedge ineffectiveness and amounts excluded from effectiveness testing.  We recognized no gains or losses resulting from hedge ineffectiveness during the first six months of 2009.
 
Additionally, during the three and six months ended June 30, 2010, we reclassified losses of $39.5 million and $87.0 million, respectively, from “Accumulated other comprehensive loss” into earnings, and for the same comparable periods last year, we reclassified losses of $30.6 million and $13.3 million, respectively, into earnings.  No material amounts were reclassified into earnings as a result of the discontinuance of cash flow hedges because it was probable that the original forecasted transactions would no longer occur by the end of the originally specified time period or within an additional two-month period of time thereafter, but rather, were reclassified as a 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 $171.4 million as of June 30, 2010, and $394.8 million as of December 31, 2009.  These totals included “Accumulated other comprehensive loss” amounts associated with energy commodity price risk management activities of $166.1 million as of June 30, 2010 and $418.2 million as of December 31, 2009.  Approximately $137.3 million of the total loss amount associated with energy
 

 
18

 

commodity price risk management activities and included in our Partners’ Capital as of June 30, 2010 is expected to be reclassified into earnings during the next twelve months (when the associated forecasted sales and purchases are also expected to occur), and as of June 30, 2010, 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 2014.
 
As of June 30, 2010, 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
(22.2) million barrels
Natural gas fixed price
(34.3) billion cubic feet
Natural gas basis
(28.1) billion cubic feet
Derivatives not designated as hedging contracts
 
Natural gas fixed price
(0.2) billion cubic feet
Natural gas basis
0.8 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.  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 December 31, 2009, we had a combined notional principal amount of $5.2 billion 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.  In the second quarter of 2010, we entered into three additional fixed-to-variable interest rate swap agreements having a combined notional principal amount of $400 million.  Each agreement effectively converts a portion of the interest expense associated with our 5.30% senior notes due September 15, 2020 from a fixed rate to a variable rate based on an interest rate of LIBOR plus a spread.
 
Accordingly, as of June 30, 2010, we had a combined notional principal amount of $5.6 billion of fixed-to-variable interest rate swap agreements.  All of our swap agreements have termination dates that correspond to the maturity dates of the related series of senior notes and, as of June 30, 2010, 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.
 
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 June 30, 2010 and December 31, 2009 (in millions):
 

 
19

 


 
Fair Value of Derivative Contracts
       
 
Asset derivatives
 
Liability derivatives
 
June 30, 2010
 
December 31, 2009
 
June 30, 2010
 
December 31, 2009
 
Balance sheet
location
 
Fair
value
 
Balance sheet
location
 
Fair
value
 
Balance Sheet
location
 
Fair
value
 
Balance sheet
Location
Fair
Value
                                     
Derivatives designated as hedging contracts
                 
Energy commodity derivative contracts
Current
 
$
36.0
 
Current
 
$
19.1
 
Current
 
$
(180.7)
 
Current
$
(270.8)
 
Non-current
   
84.8
 
Non-current
   
57.3
 
Non-current
   
(108.9)
 
Non-current
 
(241.5)
Subtotal
     
120.8
       
76.4
       
(289.6)
     
(512.3)
                                     
Interest rate swap agreements
Non-current
   
459.6
 
Non-current
   
222.5
 
Non-current
   
(41.4)
 
Non-current
 
(218.6)
Total
     
580.4
       
298.9
       
(331.0)
     
(730.9)
                                     
Derivatives not designated as hedging contracts
                 
Energy commodity derivative contracts
Current
   
8.5
 
Current
   
1.7
 
Current
   
(8.4)
 
Current
 
(1.2)
 
Non-current
   
-
 
Non-current
   
-
 
Non-current
   
-
 
Non-current
 
-
Total
     
8.5
       
1.7
       
(8.4)
     
(1.2)
                                     
Total derivatives
   
$
588.9
     
$
300.6
     
$
(339.4)
   
$
(732.1)
____________
 
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 June 30, 2010 and December 31, 2009, this unamortized premium totaled $319.3 million and $328.6 million, respectively.
 
Effect of Derivative Contracts on the Income Statement
 
The following three tables summarize the impact of our derivative contracts on our accompanying consolidated statements of income for each of the three and six months ended June 30, 2010 and 2009 (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
June 30,
         
Three Months Ended
June 30,
 
     
2010
   
2009
         
2010
   
2009
 
Interest rate swap agreements
Interest, net – income/(expense)
  $ 348.6     $ (339.4 )  
Fixed rate debt
 
Interest, net – income/(expense)
  $ (348.6 )   $ 339.4  
Total
    $ 348.6     $ (339.4 )  
Total
    $ (348.6 )   $ 339.4  
                                         
                                         
     
Six Months Ended
June 30,
         
Six Months Ended
June 30,
 
        2010       2009             2010       2009  
Interest rate swap agreements
Interest, net – income/(expense)
  $ 414.2     $ (469.8 )  
Fixed rate debt
 
Interest, net – income/(expense)
  $ (414.2 )   $ 469.8  
Total
    $ 414.2     $ (469.8 )  
Total
    $ (414.2 )   $ 469.8  
____________

 (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.


 
20

 


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 Ended
June 30,
     
Three Months Ended
June 30,
     
Three Months Ended
June 30,
   
2010
 
2009
     
2010
 
2009
     
2010
 
2009
Energy commodity derivative contracts
 
$
143.1
 
$
(339.5)
 
Revenues-natural gas sales
 
$
1.7
 
$
4.8
 
Revenues-product sales and other
 
$
7.9
 
$
-
               
Revenues-product sales and other
   
(48.4)
   
(28.9)
               
               
Gas purchases and other costs of sales
   
7.2
   
(6.5)
 
Gas purchases and other costs of sales
   
(0.1)
   
-
Total
 
$
143.1
 
$
(339.5)
 
Total
 
$
(39.5)
 
$
(30.6)
 
Total
 
$
7.8
 
$
-
                                               
   
Six Months Ended
June 30,
     
Six Months Ended
June 30,
     
Six Months Ended
June 30,
   
2010
 
2009
     
2010
 
2009
     
2010
 
2009
Energy commodity derivative contracts
 
$
167.7
 
$
(303.6)
 
Revenues-natural gas sales
 
$
1.7
 
$
6.5
 
Revenues-product sales and other
 
$
13.3
 
$
-
               
Revenues-product sales and other
   
(98.4)
   
(12.9)
               
               
Gas purchases and other costs of sales
   
9.7
   
(6.9)
 
Gas purchases and other costs of sales
   
0.8
   
-
Total
 
$
167.7
 
$
(303.6)
 
Total
 
$
(87.0)
 
$
(13.3)
 
Total
 
$
14.1
 
$
-
____________
 
 
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
June 30,
 
     
2010
   
2009
 
Energy commodity derivative contracts
Gas purchases and other costs of sales
  $ 0.1     $ (1.9 )
Total
    $ 0.1     $ (1.9 )
                   
     
Six Months Ended
June 30,
 
        2010       2009  
Energy commodity derivative contracts
Gas purchases and other costs of sales
  $ 0.8     $ (2.3 )
Total
    $ 0.8     $ (2.3 )
____________
 
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.
 

 
21

 

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 June 30, 2010 was (in millions):
 
   
Asset position
 
Interest rate swap agreements
  $ 459.6  
Energy commodity derivative contracts
    129.3  
Gross exposure
    588.9  
Netting agreement impact
    (93.6 )
Net exposure
  $ 495.3  

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 December 31, 2009, we had outstanding letters of credit totaling $55.0 million in support of our hedging of energy commodity price risks associated with the sale of natural gas, natural gas liquids and crude oil.  As of June 30, 2010 and December 31, 2009, we had cash margin deposits associated with our energy commodity contract positions and over-the-counter swap partners totaling $19.3 million and $15.2 million, respectively, and we reported these amounts as “Restricted deposits” in our accompanying consolidated balance sheets.
 
We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring us to post additional collateral upon a decrease in our credit rating.  Based on contractual provisions as of June 30, 2010, 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
 
$
3.7
   
$
23.0
 
                 
Two notches to below BBB-/Baa3 (below investment grade)
 
$
90.8
   
$
113.8
 
____________

(a)
If there are split ratings among the independent credit rating agencies, most counterparties use the higher credit rating to determine our incremental collateral obligations, while the remaining use the lower credit rating.  Therefore, a one notch downgrade to BBB-/Baa3 by one agency would not trigger the entire $3.7 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.
 

 
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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 June 30, 2010 and December 31, 2009, based on the three levels established by the Codification (in millions):
 
   
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 June 30, 2010
                       
Energy commodity derivative contracts(a)
  $ 129.3     $ -     $ 55.1     $ 74.2  
Interest rate swap agreements
  $ 459.6     $ -     $ 459.6     $ -  
                                 
As of December 31, 2009
                               
Energy commodity derivative contracts(a)
  $ 78.1     $ -     $ 14.4     $ 63.7  
Interest rate swap agreements
  $ 222.5     $ -     $ 222.5     $ -  
____________
 
   
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 June 30, 2010
                       
Energy commodity derivative contracts(b)
  $ (298.0 )   $ -     $ (270.4 )   $ (27.6 )
Interest rate swap agreements
  $ (41.4 )   $ -     $ (41.4 )   $ -  
                                 
As of December 31, 2009
                               
Energy commodity derivative contracts(b)
  $ (513.5 )   $ -     $ (462.8 )   $ (50.7 )
Interest rate swap agreements
  $ (218.6 )   $ -     $ (218.6 )   $ -  
____________
 
(a)
Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on NYMEX.  Level 3 consists primarily of natural gas basis swaps, West Texas Sour hedges, natural gas options, and West Texas Intermediate options.
(b)
Level 2 consists primarily of OTC West Texas Intermediate hedges and OTC natural gas hedges that are settled on NYMEX. Level 3 consists primarily of natural gas basis swaps, West Texas Sour hedges, and West Texas Intermediate options.
 
The fair value measurements in the tables above do not include cash margin deposits, which are reported separately as “Restricted deposits” in our accompanying consolidated balance sheets.  The table below provides a summary of changes in the fair value of our Level 3 energy commodity derivative contracts for each of the three and six months ended June 30, 2010 and 2009 (in millions):
 

 
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Significant unobservable inputs (Level 3)
 
             
   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Derivatives-net asset (liability)
                       
Beginning of Period
  $ 22.6     $ 53.4     $ 13.0     $ 44.1  
Realized and unrealized net gains and (losses)
    18.1       (28.1 )     26.7       (21.8 )
Purchases and settlements
    5.9       (1.3 )     6.9       1.7  
Transfers in (out) of Level 3
    -       -       -       -  
End of Period
  $ 46.6     $ 24.0     $ 46.6     $ 24.0  
                                 
Change in unrealized net losses relating to contracts still
                               
held at end of period
  $ 19.2     $ (29.7 )   $ 24.1     $ (39.5 )

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 June 30, 2010 and December 31, 2009 (both short-term and long-term, but excluding the value of interest rate swaps), is disclosed below (in millions):
 
   
June 30, 2010
 
December 31, 2009
   
Carrying
Value
   
Estimated
fair value
 
Carrying
value
 
Estimated
fair value
Total Debt
  $ 11,850.8     $ 12,678.9     $ 10,592.4     $ 11,265.7  

 
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.  Each segment is managed separately because each segment involves different products and marketing strategies.
 

 
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Financial information by segment follows (in millions):
 
   
Three Months Ended
June 30,
   
Six Months Ended
June 30,
 
   
2010
   
2009
   
2010
   
2009
 
Revenues